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| issue date = 01/12/2006
| issue date = 01/12/2006
| title = Safety Evaluation Report Related to the License Renewal of Browns Ferry Nuclear Plant, Units 1, 2, and 3 (Tac Nos. MC1704, MC1705, MC1706)
| title = Safety Evaluation Report Related to the License Renewal of Browns Ferry Nuclear Plant, Units 1, 2, and 3 (Tac Nos. MC1704, MC1705, MC1706)
| author name = Gillespie F P
| author name = Gillespie F
| author affiliation = NRC/NRR/ADRO/DLR
| author affiliation = NRC/NRR/ADRO/DLR
| addressee name = Singer K W
| addressee name = Singer K
| addressee affiliation = Tennessee Valley Authority
| addressee affiliation = Tennessee Valley Authority
| docket = 05000259, 05000260, 05000296
| docket = 05000259, 05000260, 05000296
Line 19: Line 19:


=Text=
=Text=
{{#Wiki_filter:Safety Evaluation Report Related to the License Renewal of the Browns Ferry Nuclear Plant, Units 1, 2, and 3 Docket Nos. 50-259, 50-260, and 50-296Tennessee Valley Authority U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation January 12, 2006 THIS PAGE IS INTENTIONALLY LEFT BLANK.
{{#Wiki_filter:}}
iii ABSTRACT This safety evaluation report (SER) documents the technical review of the Browns Ferry Nuclear Plant (BFN), Units 1, 2, and 3, license renewal application (LRA) by the staff of the U.S. Nuclear
 
Regulatory Commission (NRC) (the staff). By letter dated December 31, 2003, Tennessee
 
Valley Authority (TVA or the applicant) submitted the LRA for BFN in accordance with Title 10, Part 54, of the Code of Federal Regulations (10 CFR Part 54). TVA is requesting renewal of the operating licenses for BFN Units 1, 2, and 3, (Facility Operating License Numbers DPR-33, DPR-52, and DPR-68, respectively) for a period of 20 years beyond the current expiration dates
 
of midnight December 20, 2013, for Unit 1; midnight June 28, 2014, for Unit 2; and midnight
 
July 2, 2016, for Unit 3.
The BFN units are located on the north shore of Wheeler Reservoir in Limestone County, Alabama, at Tennessee River Mile 294. The site is approximately 30 miles west of Huntsville, Alabama; it is also 10 miles northwest of Decatur, Alabama and 10 miles southwest of Athens, Alabama. The NRC issued the construction permits for Units 1 and 2 on May 10, 1967; for
 
Unit 3 on July 31, 1968. The NRC issued the operating licenses for Unit 1 on December 20, 1973; for Unit 2 on June 28, 1974; and for Unit 3 on July 2, 1976. All of the units consist of a
 
Mark I boiling water reactor (BWR) with a nuc lear steam supply system supplied by General Electric Corporation. The balance of each of the plants was originally designed and constructed
 
by the Tennessee Valley Authority. Unit 1 licensed power output is 3293 megawatt thermal (MWt), with a gross electrical output of appr oximately 1100 megawatt electric (MWe). Units 2 and 3 licensed power output is 3458 MWt, with a gross electrical output of approximately 1155
 
MWe. The units operated from the original licensing until 1985 when they were voluntarily shut
 
down by the applicant to address management and technical issues. The applicant then
 
implemented a comprehensive nuclear performance plan to correct the deficiencies that led to
 
the shutdown. This plan included changes in management, programs, processes and
 
procedures, as well as extensive equipment re furbishment, replacement, and modifications.
Unit 2 was subsequently restarted in 1991, and Unit 3 followed in 1995. In the early 1990s, the
 
applicant decided to defer restart of Unit 1. Unit 1 is currently in a shutdown status.
This SER presents the status of the staff's review of information submitted to the NRC through December 31, 2005, the cutoff date for consideration in the SER. The staff identified open items
 
and confirmatory items that had to be resolved before the staff could make a final determination
 
on the application. SER Sections 1.5 and 1.6 summarize these items and their resolutions.
 
Section 6 provides the staff's final conclusion on the review of the BFN LRA.
THIS PAGE IS INTENTIONALLY LEFT BLANK.
v TABLE OF CONTENTSAbstract...................................................................iiiTable of Contents............................................................vAbbreviations..............................................................xv
 
1  Introduction and General Discussion.........................................1-1 1.1  Introduction.....................................................1-1
 
===1.2 License===
Renewal Background.......................................1-31.2.1  Safety Review............................................1-3
 
====1.2.2 Environmental====
Review.....................................1-51.3  Principal Review Matters...........................................1-5
 
====1.3.1 Operating====
Experience for BFN Unit 1 in Satisfying the Intent of the License Renewal Rule...........................................1-51.3.1.1  Regulatory Framework..............................1-61.3.1.2  Collective Operating Experience of the Three BFN Units...1-6 1.3.1.3  Corrective Action Program (CAP) Applicability...........1-7 1.3.1.4  Aging Mechanism Similarities Between Units after Layup andRecovery.........................................1-71.3.1.5  Plant Upgrades ...................................1-8 1.3.1.6  Inspections/Programs Expanded to Proactively Prevent AgeRelated Wear.....................................1-8
 
====1.3.2 License====
Renewal at Currently Licensed Power Level.............1-101.3.3  Integration of Unit 1 Restart Modification......................1-10
 
====1.3.4 Other====
Regulatory Requirements.............................1-101.4  Interim Staff Guidance............................................1-12
 
===1.5 Summary===
of Open Items..........................................1-151.6  Summary of Confirmatory Items....................................1-17
 
===1.7 Summary===
of Proposed License Conditions............................1-18 2  Structures and Components Subject to Aging Management Review.................2-1
 
===2.1 Scoping===
and Screening Methodology.................................2-1 2.1.1  Introduction..............................................2-12.1.2  Summary of Technical Information in the Application..............2-1 2.1.2.1  Scoping Methodology...............................2-2 2.1.2.2  Screening Methodology.............................2-52.1.3  Staff Evaluation...........................................2-6 2.1.3.1  Scoping Methodology...............................2-7 2.1.3.2  Screening Methodology............................2-242.1.4  Conclusion.............................................2-272.2  Plant-Level Scoping Results.......................................2-28 2.2.1  Introduction.............................................2-282.2.2  Summary of Technical Information in the Application.............2-28
 
====2.2.3 Staff====
Evaluation..........................................2-28 2.2.4  Conclusion.............................................2-302.3  Scoping and Screening Results: Mechanical Systems...................2-31 vi2.3.1  Reactor Coolant Systems..................................2-372.3.1.1  Reactor Vessel...................................2-37 2.3.1.2  Reactor Vessel Internals...........................2-39
 
2.3.1.3  Reactor Vessel Vents and Drains System..............2-422.3.1.4  Reactor Recirculation System.......................2-43
 
====2.3.2 Engineered====
Safety Features................................2-452.3.2.1  Containment System..............................2-46
 
2.3.2.2  Standby Gas Treatment System.....................2-492.3.2.3  High Pressure Coolant Injection System...............2-51
 
2.3.2.4  Residual Heat Removal System......................2-532.3.2.5  Core Spray System...............................2-54 2.3.2.6  Containment Inerting System........................2-56
 
2.3.2.7  Containment Atmosphere Dilution System..............2-582.3.3  Auxiliary Systems........................................2-60 2.3.3.1  Auxiliary Boiler System............................2-61 2.3.3.2  Fuel Oil System..................................2-62 2.3.3.3  Residual Heat Removal Service Water System..........2-642.3.3.4  Raw Cooling Water System.........................2-66 2.3.3.5  Raw Service Water System.........................2-68 2.3.3.6  High Pressure Fire Protection System.................2-70 2.3.3.7  Potable Water System.............................2-75 2.3.3.8  Ventilation System................................2-76
 
2.3.3.9  Heating, Ventilation, and Air Conditioning System........2-782.3.3.10  Control Air System...............................2-81 2.3.3.11  Service Air System...............................2-82
 
2.3.3.12  CO 2 System....................................2-84 2.3.3.13  Station Drainage System..........................2-86 2.3.3.14  Sampling and Water Quality System.................2-882.3.3.15  Building Heat System.............................2-90 2.3.3.16  Raw Water Chemical Treatment System..............2-92 2.3.3.17  Demineralizer Backwash Air System.................2-93
 
2.3.3.18  Standby Liquid Control System.....................2-942.3.3.19  Off-Gas System.................................2-96
 
2.3.3.20  Emergency Equipment Cooling Water System.........2-98 2.3.3.21  Reactor Water Cleanup System....................2-1002.3.3.22  Reactor Building Closed Cooling Water System.......2-105 2.3.3.23  Reactor Core Isolation Cooling System..............2-109
 
2.3.3.24  Auxiliary Decay Heat Removal System..............2-1112.3.3.25  Radioactive Waste Treatment System...............2-112
 
2.3.3.26  Fuel Pool Cooling and Cleanup System.............2-114 2.3.3.27  Fuel Handling and Storage System.................2-116 2.3.3.28  Diesel Generator System.........................2-1182.3.3.29  Control Rod Drive System........................2-120
 
2.3.3.30  Diesel Generator Starting Air System...............2-1212.3.3.31  Radiation Monitoring System......................2-123 2.3.3.32  Neutron Monitoring System.......................2-125
 
2.3.3.33  Traversing In-Core Probe System..................2-127 2.3.3.34  Cranes System.................................2-1282.3.4  Steam and Power Conversion Systems......................2-130 vii2.3.4.1  Main Steam System..............................2-130 2.3.4.2  Condensate and Demineralized Water System.........2-134 2.3.4.3  Feedwater System...............................2-136 2.3.4.4  Heater Drains and Vents System....................2-137 2.3.4.5  Turbine Drains and Miscellaneous Piping System.......2-140 2.3.4.6  Condenser Circulating Water System................2-142 2.3.4.7  Gland Seal Water System.........................2-144
 
===2.4 Scoping===
and Screening Results: Structures..........................2-1462.4.1  Boiling Water Reactor Containment Structures................2-1472.4.1.1  Primary Containment Structure.....................2-147
 
====2.4.2 Class====
1 Group 2 Structures................................2-1562.4.2.1  Reactor Buildings................................2-157 2.4.2.2  Equipment Access Lock...........................2-163
 
====2.4.3 Class====
1 Group 3 Structures................................2-165 2.4.3.1  Diesel Generator Buildings........................2-1652.4.3.2  Standby Gas Treatment Building....................2-1682.4.3.3  Off-Gas Treatment Building........................2-169 2.4.3.4  Vacuum Pipe Building............................2-171 2.4.3.5  Residual Heat Removal Service Water Tunnels........2-173 2.4.3.6  Electrical Cable Tunnel from the Intake Pumping Station to thePowerhouse....................................2-175 2.4.3.7  Underground Concrete Encased Structures...........2-1772.4.3.8  Earth Berm.....................................2-180 2.4.3.9  South Access Retaining Walls......................2-181
 
====2.4.4 Class====
1 Group 6 Structures................................2-1822.4.4.1  Intake Pumping Station...........................2-182 2.4.4.2  Gate Structure No. 3.............................2-184
 
2.4.4.3  Intake Channel..................................2-185 2.4.4.4  North Bank of the Cool Water Channel East of Gate Structure No.2.............................................2-187 2.4.4.5  South Dike of Cool Water Channel between Gate Structure Nos.2 and 3........................................2-188
 
====2.4.5 Class====
1 Group 8 Structures................................2-190 2.4.5.1  Condensate Water Storage Tanks' Foundations and Trenches..............................................2-190 2.4.5.2  Containment Atmosphere Dilution Storage Tanks' Foundations..............................................2-192
 
====2.4.6 Class====
1 Group 9 Structures................................2-1942.4.6.1  Reinforced Concrete Chimney......................2-1942.4.7  Non-Class 1 Structures...................................2-1962.4.7.1  Turbine Buildings................................2-196 2.4.7.2  Diesel High Pressure Fire Pump House..............2-198 2.4.7.3  Vent Vaults.....................................2-200 2.4.7.4  Transformer Yard................................2-202
 
2.4.7.5  161 kV Switchyard...............................2-203 2.4.7.6  500 kV Switchyard...............................2-2052.4.7.7  Isolation Valve Pits...............................2-207 2.4.7.8  Radwaste Building...............................2-208 2.4.7.9 Service Building.................................2-210 viii 2.4.8  Structures and Component Supports Commodities.............2-2122.4.8.1  Structures and Component Supports Commodity Group..2-2122.4.9  Conclusion............................................2-216
 
===2.5 Scoping===
and Screening Results: Electrical and Instrumentation and ControlsSystems...................................................2-217
 
====2.5.1 Electrical====
and Instrumentation and Control Commodities.........2-2172.5.1.1  Summary of Technical Information in the Application....2-217 2.5.1.2  Staff Evaluation.................................2-218 2.5.1.3  Conclusion.....................................2-223
 
===2.6 Integration===
of Browns Ferry Nuclear, Unit 1, Restart Activities and License RenewalActivities...................................................2-224
 
====2.6.1 Regulatory====
Framework for Review of BFN LRA and Integration Unit 1Restart Activities.......................................2-224
 
2.6.1.1  Main Steam Isolation Valve Alternate Leakage Treatment..............................................2-2272.6.1.2  Containment Atmosphere Dilution System ............2-2282.6.1.3  Fire Protection ..................................2-230 2.6.1.4  Environmental Qualification .......................2-232
 
2.6.1.5  Intergranular Stress Corrosion Cracking..............2-234 2.6.1.6  Boiling Water Reactor Vessel and Internals Project Inspection and Flaw Evaluation Guidelines Implementation ........2-2352.6.1.7  Anticipated Transients Without Scram................2-2372.6.1.8  Reactor Vessel Head Spray........................2-238 2.6.1.9  Hardened Wetwell Vent...........................2-239 2.6.1.10  Service Air and Demineralized Water Primary ContainmentPenetrations ....................................2-240 2.6.1.11  Auxiliary Decay Heat Removal System..............2-241 2.6.1.12  Maintenance Rule..............................2-243 2.6.1.13  Reactor Water Cleanup System....................2-2442.6.2  Staff Evaluation.........................................2-245 2.6.3Conclusion...........................................2-246
 
===2.7 Conclusion===
for Scoping and Screening..............................2-2473  Aging Management Review Results..........................................3-13.0  Applicant's Use of the Generic Aging Lessons Learned Report.............3-13.0.1  Format of the License Renewal Application.....................3-23.0.1.1  Overview of Table 1................................3-33.0.1.2  Overview of Table 2................................3-33.0.2  Staff's Review Process.....................................3-43.0.2.1  Review of AMPs...................................3-4 3.0.2.2  Review of AMR Results.............................3-6
 
3.0.2.3  UFSAR Supplement................................3-6 3.0.2.4  Documentation and Documents Reviewed..............3-63.0.3  Aging Management Programs...............................3-6 3.0.3.1  AMPs That Are Consistent with the GALL Report, for Which Further Evaluation is Not Recommended...............3-11 3.0.3.2  AMPs That Are Consistent with the GALL Report with Exceptionsor Enhancements.................................3-26 ix 3.0.3.3  AMPs That Are Not Consistent with or Not Addressed in theGALL Report....................................3-101
 
====3.0.4 Quality====
Assurance Program Attributes Integral to Aging ManagementPrograms.............................................3-118 3.0.4.1  Summary of Technical Information in the Application....3-118 3.0.4.2  Staff Evaluation.................................3-119 3.0.4.3  Conclusion.....................................3-121
 
===3.1 Aging===
Management Review of Reactor Vessel, Internals, and Reactor CoolantSystem....................................................3-122
 
====3.1.1 Summary====
of Technical Information in the Application............3-122
 
====3.1.2 Staff====
Evaluation.........................................3-122 3.1.2.1  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Not Recommended.........3-126 3.1.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended............3-130 3.1.2.3  AMR Results That Are Not Consistent with or Not Addressed inthe GALL Report.................................3-1413.1.3  Conclusion............................................3-176
 
===3.2 Aging===
Management of Engineered Safety Features....................3-1773.2.1  Summary of Technical Information in the Application............3-177
 
====3.2.2 Staff====
Evaluation.........................................3-177 3.2.2.1  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation Is Not Recommended........3-180 3.2.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation Is Recommended............3-183 3.2.2.3  AMR Results That Are Not Consistent with or Not Addressed inthe GALL Report.................................3-1873.2.3  Conclusion............................................3-2013.3  Aging Management of Auxiliary Systems............................3-2023.3.1  Summary of Technical Information in the Application............3-202
 
====3.3.2 Staff====
Evaluation.........................................3-203 3.3.2.1  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Not Recommended.........3-209 3.3.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended............3-211 3.3.2.3  AMR Results That Are Not Consistent with or Not Addressed inthe GALL Report.................................3-2213.3.3  Conclusion............................................3-261
 
===3.4 Aging===
Management of Steam and Power Conversion System............3-2623.4.1  Summary of Technical Information in the Application............3-262
 
====3.4.2 Staff====
Evaluation.........................................3-262 3.4.2.1  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Not Recommended.........3-265 3.4.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended............3-267 3.4.2.3  AMR Results That Are Not Consistent with or Not Addressed inthe GALL Report.................................3-2703.4.3  Conclusion............................................3-278 x 3.5  Aging Management of Containments, Structures, and Component Supports..........................................................3-2793.5.1  Summary of Technical Information in the Application............3-279
 
====3.5.2 Staff====
Evaluation.........................................3-280 3.5.2.1  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Not Recommended.........3-285 3.5.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended............3-289 3.5.2.3  AMR Results That Are Not Consistent with or Not Addressed inthe GALL Report.................................3-3043.5.3  Conclusion............................................3-349
 
===3.6 Aging===
Management of Electrical and Instrumentation and Controls........3-3513.6.1  Summary of Technical Information in the Application............3-351
 
====3.6.2 Staff====
Evaluation.........................................3-351 3.6.2.1  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Not Recommended.........3-353 3.6.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended............3-355 3.6.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report.................................3-3563.6.3  Conclusion............................................3-362
 
===3.7 Aging===
Management Review of Unit 1 Systems in Layup for Extended Outage..........................................................3-363
 
====3.7.1 General====
Technical Concerns..............................3-3633.7.1.1  Wet Layup Program Chemistry Control...............3-368 3.7.1.2  Replaced Components............................3-369 3.7.1.3  Inspections Verification Programs for Layup and ChemistryControl.........................................3-3713.7.1.4  MIC...........................................3-378
 
3.7.1.5  Transition from Layup Program to System CleanlinessVerification Program..............................3-381
 
====3.7.2 Reactor====
Vessel internals and Reactor Coolant System..........3-382 3.7.2.1 Reactor Recirculation System (068)..................3-3823.7.2.2  Reactor Vessel (RV), Reactor Vessel Internals (RVIs)...3-385
 
====3.7.3 Engineered====
Safety Features...............................3-391 3.7.3.1  Engineered Safety Features Systems in Dry Layup......3-391 3.7.3.2  Engineered Safety Features Systems in Various WetEnvironments...................................3-395 3.7.3.3  Engineered Safety Features Systems in Various DryEnvironments...................................3-4033.7.4  Auxiliary Systems.......................................3-407 3.7.4.1  Auxiliary Systems in Dry Layup.....................3-407 3.7.4.2  Auxiliary Systems in Wet Lay up....................3-413 3.7.4.3  Auxiliary Systems Not in Layup Program..............3-4183.7.5  Steam and Power Conversion Systems......................3-420 3.7.5.1  Steam and Power Conversion Systems in Wet Layup....3-420 3.7.5.2  Steam and Power Conversion Systems in Various WetEnvironments...................................3-423 xi 3.7.5.3  Steam and Power Conversion Systems in Various DryEnvironments...................................3-430 3.7.6  Containments, Structures, and Component Supports...........3-4373.7.6.1  Summary of Technical Information in the Application....3-437 3.7.6.2  Technical Staff Evaluation.........................3-437 3.7.6.3  Conclusion.....................................3-442
 
===3.8 Conclusion===
for Aging Management.................................3-4434  Time-Limited Aging Analyses...............................................4-1
 
===4.1 Identification===
of Time-Limited Aging Analyses...........................4-14.1.1  Summary of Technical Information in the Application..............4-1
 
====4.1.2 Staff====
Evaluation...........................................4-2 4.1.3  Conclusion..............................................4-34.2  Neutron Embrittlement of Reactor Vessel and Internals...................4-3
 
====4.2.1 Reactor====
Vessel Materials Upper Shelf Energy Reduction due to NeutronEmbrittlement...........................................4-4 4.2.1.1  Summary of Technical Information in the Application......4-4 4.2.1.2  Staff Evaluation...................................4-6
 
4.2.1.3  UFSAR Supplement................................4-74.2.1.4  Conclusion.......................................4-8
 
====4.2.2 Adjusted====
Reference Temperature for Reactor Vessel Materials due toNeutron Embrittlement....................................4-8 4.2.2.1  Summary of Technical Information in the Application......4-8 4.2.2.2  Staff Evaluation...................................4-9
 
4.2.2.3  UFSAR Supplement...............................4-104.2.2.4  Conclusion......................................4-104.2.3  Reflood Thermal Shock Analysis of the Reactor Vessel...........4-104.2.3.1  Summary of Technical Information in the Application.....4-10 4.2.3.2  Staff Evaluation..................................4-11
 
4.2.3.3  UFSAR Supplement...............................4-114.2.3.4  Conclusion......................................4-11
 
====4.2.4 Reflood====
Thermal Shock Analysis of the Reactor Vessel Core Shroud.....................................................4-124.2.4.1  Summary of Technical Information in the Application.....4-12 4.2.4.2  Staff Evaluation..................................4-12
 
4.2.4.3  UFSAR Supplement...............................4-144.2.4.4  Conclusion......................................4-14
 
====4.2.5 Reactor====
Vessel Thermal Limit Analyses: Operating Pressure-TemperatureLimits.................................................4-15 4.2.5.1  Summary of Technical Information in the Application.....4-15 4.2.5.2  Staff Evaluation..................................4-15
 
4.2.5.3  UFSAR Supplement...............................4-154.2.5.4  Conclusion......................................4-164.2.6  Reactor Vessel Circumferential Weld Examination Relief.........4-164.2.6.1  Summary of Technical Information in the Application.....4-16 4.2.6.2  Staff Evaluation..................................4-17
 
4.2.6.3  UFSAR Supplement...............................4-204.2.6.4  Conclusion......................................4-204.2.7  Reactor Vessel Axial Weld Failure Probability..................4-21 xii4.2.7.1  Summary of Technical Information in the Application.....4-214.2.7.2  Staff Evaluation..................................4-21
 
4.2.7.3  UFSAR Supplement...............................4-224.2.7.4  Conclusion......................................4-234.3  Metal Fatigue...................................................4-23
 
====4.3.1 Reactor====
Vessel Fatigue Analysis............................4-234.3.1.1  Summary of Technical Information in the Application.....4-23 4.3.1.2  Staff Evaluation..................................4-24
 
4.3.1.3  UFSAR Supplement...............................4-244.3.1.4  Conclusion......................................4-254.3.2  Fatigue Analysis of Reactor Vessel Internals...................4-254.3.2.1  Summary of Technical Information in the Application.....4-25 4.3.2.2  Staff Evaluation..................................4-26
 
4.3.2.3  UFSAR Supplement...............................4-264.3.2.4  Conclusion......................................4-26
 
====4.3.3 Piping====
and Component Fatigue Analysis......................4-274.3.3.1  Summary of Technical Information in the Application.....4-27 4.3.3.2  Staff Evaluation..................................4-27
 
4.3.3.3  UFSAR Supplement...............................4-284.3.3.4  Conclusion......................................4-28
 
====4.3.4 Effects====
of Reactor Coolant Environment On Fatigue Life of Components and Piping (Generic Safety Issue 190).......................4-284.3.4.1  Summary of Technical Information in the Application.....4-28 4.3.4.2  Staff Evaluation..................................4-29
 
4.3.4.3  UFSAR Supplement...............................4-304.3.4.4  Conclusion......................................4-304.4  Environmental Qualification........................................4-314.4.1  Summary of Technical Information in the Application.............4-31
 
====4.4.2 Staff====
Evaluation..........................................4-33
 
====4.4.3 UFSAR====
Supplement......................................4-344.4.4  Conclusion.............................................4-34 4.5  Loss of Prestress in Concrete Containment Tendons....................4-344.6  Primary Containment Fatigue......................................4-34
 
====4.6.1 Fatigue====
of Suppression Chamber, Vents, and Downcomers.......4-354.6.1.1  Summary of Technical Information in the Application.....4-35 4.6.1.2  Staff Evaluation..................................4-36
 
4.6.1.3  UFSAR Supplement...............................4-374.6.1.4  Conclusion......................................4-37
 
====4.6.2 Fatigue====
of Torus Attached Pipe and Safety Relief Valve Discharge Lines.....................................................4-374.6.2.1  Summary of Technical Information in the Application.....4-37 4.6.2.2  Staff Evaluation..................................4-38
 
4.6.2.3  UFSAR Supplement...............................4-384.6.2.4  Conclusion......................................4-38
 
====4.6.3 Fatigue====
of Vent Line and Process Penetration Bellows...........4-394.6.3.1  Summary of Technical Information in the Application.....4-39 4.6.3.2  Staff Evaluation..................................4-39
 
4.6.3.3  UFSAR Supplement...............................4-404.6.3.4  Conclusion......................................4-40 xiii4.7  Other Plant-Specific Analyses......................................4-40
 
====4.7.1 Reactor====
Building Crane Load Cycles.........................4-404.7.1.1  Summary of Technical Information in the Application.....4-40 4.7.1.2  Staff Evaluation..................................4-41
 
4.7.1.3  UFSAR Supplement...............................4-414.7.1.4  Conclusion......................................4-42
 
====4.7.2 Corrosion====
- Flow Reduction................................4-42 4.7.3  Dose to Seal Rings for the High Pressure Coolant Injection and ReactorCore Isolation Cooling Containment Isolation Check Valves......4-42
 
====4.7.4 Radiation====
Degradation of Drywell Expansion Gap Foam..........4-424.7.4.1  Summary of Technical Information in the Application.....4-42 4.7.4.2  Staff Evaluation..................................4-43
 
4.7.4.3  UFSAR Supplement...............................4-444.7.4.4  Conclusion......................................4-444.7.5  Corrosion - Minimum Wall Thickness.........................4-45
 
====4.7.6 Irradiation====
Assisted Stress Corrosion Cracking of Reactor Vessel Internals.....................................................4-454.7.6.1  Summary of Technical Information in the Application.....4-45 4.7.6.2  Staff Evaluation..................................4-46
 
4.7.6.3  UFSAR Supplement...............................4-494.7.6.4  Conclusion......................................4-494.7.7  Stress Relaxation of the Core Plate Hold-Down Bolts............4-504.7.7.1  Summary of Technical Information in the Application.....4-50 4.7.7.2  Staff Evaluation..................................4-50
 
4.7.7.3  UFSAR Supplement...............................4-574.7.7.4  Conclusion......................................4-574.7.8  Emergency Equipment Cooling Water Weld Flaw Evaluation......4-584.7.8.1  Summary of Technical Information in the Application.....4-58 4.7.8.2  Staff Evaluation..................................4-58
 
4.7.8.3  UFSAR Supplement...............................4-604.7.8.4  Conclusion......................................4-614.8  Conclusion for Time-Limited Aging Analyses..........................4-61 5  Review by the Advisory Committee on Reactor Safeguards.......................5-16  Conclusions............................................................6-1 AppendicesAppendix A:  Commitments for License Renewals.................................A-1 Appendix B:  Chronology....................................................B-1Appendix C:  Principal Contributors............................................C-1 Appendix D:  References....................................................D-1 Tables xivTable 3.0.3-1  BFN's Aging Management Programs...............................3-7 Table 3.1-1  Staff Evaluation for Reactor Vessel, Internals, and Reactor Coolant SystemComponents in the GALL Report......................................3-123 Table 3.2-1  Staff Evaluation for Engineered Sa fety Features System Components in the GALLReport...........................................................3-178 Table 3.3-1  Staff Evaluation for Auxiliary Systems Components in the GALL Report...3-204 Table 3.4-1  Staff Evaluation for Steam and Power Conversion System Components in theGALL Report......................................................3-263 Table 3.5-1  Staff Evaluation for Containments, Structures, and Component Supports in theGALL Report......................................................3-280 Table 3.6-1  Staff Evaluation for Electrical and Instrumentation and Controls in the GALL Report...........................................................3-352 xv ABBREVIATIONSACalternating currentACIAmerican Concrete Institute ACSRaluminum conductor steel reinforced ACRSAdvisory Committee on Reactor Safeguards ADHRauxiliary decay heat removal ADSatmospheric dilution system AERMaging effect requiring management AFFFaqueous film-forming foam AFWauxiliary feedwater AHCaccess hole cover AISCAmerican Institute of Steel Construction AMPaging management program AMRaging management review ANSIAmerican National Standards Institute APCSBAuxiliary and Power Conversion Systems Branch APRMaverage power range monitor URIunresolved issue ARTadjusted reference temperature ASCEAmerican Society of Civil Engineers ASMEAmerican Society of Mechanical Engineers ASTalternate source term ASTMAmerican Society for Testing and Materials ATWSanticipated transient without scramB&PVboiler and pressure vesselB&WBabcock and Wilcox BFNBrowns Ferry Nuclear Plant BWRboiling water reactor BWROGBoiling Water Reactor Owners Group BWRVIPBoiling Water Reactor Vessel and Internals ProjectCADcontainment atmosphere dilutionCASScast austentitic stainless steel CBFcycle-based fatigue CCCWclosed-cycle cooling water CCWPcondensate circulating water pump CFchemistry factor
 
CFR Code of Federal RegulationsCIconfirmatory item CLBcurrent licensing basis CMAACrane Manufacturers Association of America
 
CO 2 carbon dioxideCRDcontrol rod drive CScore spray CUFcumulative usage factor CVPCleanliness Verification Program xviCWSTcondensate water storage tank DBAdesign-basis accidentDBEdesign-basis event DCdesign of civil structures DCNdesign change notice DGdiesel generator or Draft Regulatory Guide DGBdiesel generator building dpadisplacements per atomECCSemergency core cooling systemECPelectrochemical potential EDGemergency diesel generator EECWemergency equipment cooling water EFPYeffective full-power year EMAequivalent margin analysis EMPACenterprise maintenance planning and control EOLend of life EPRIElectric Power Research Institute EPUextended power uprate EQenvironmental qualification ESFengineered safety feature EVTenhanced visual testFACflow-accelerated corrosion F en environmental fatigue life correction factorFERCFederal Energy Regulatory Commission FPfire protection FPCfuel pool cooling and cleanup FPRFire Protection Report FSARfinal safety analysis report FWfeedwaterGALLGeneric Aging Lessons Learned ReportGDCgeneral design criteria GEGeneral Electric Corporation GEISGeneric Environmental Impact Statement GENEGeneral Electric Nuclear Energy GESgeneral engineering specification GLgeneric letter GSIgeneric safety issueHELBhigh-energy line breakHEPAhigh efficiency particulate air HHhandhole HPCIhigh pressure coolant injection HPFPhigh pressure fire protection HSLAhigh-strength low-alloy HVACheating, ventilation, and air conditioning xviiHWChydrogen water chemistryHXheat exchangerI&Cinstrumentation and controlIASCCirradiation assisted stress corrosion cracking IDinside diameter IGSCCintergranular stress corrosion cracking INinformation notice INPOInstitute of Nuclear Power Operations IPAintegrated plant assessment IPSintake pumping station IRinsulation resistance IRMintermediate range monitor ISGinterim staff guidance ISIinservice inspection ISPIntegrated Surveillance ProgramkVkiloVolt LERLicensee Event ReportLLRTlocal leak rate test LLRWlow level radioactive waste LOCAloss-of-coolant-accident LPlayup program LPCIlow pressure coolant injection LPRMlocal power range monitor LRlicense renewal LRAlicense renewal application LTOPlow temperature over-pressure LWRlight water reactor MEAP material, environment, aging effects, and aging management programMELmaster equipment list MeVmillion electron Volts MICmicrobiologically influenced corrosion MSmain steam MSIVmain steam isolation valve MWemegawatt electric MWtmegawatt thermal n/cm 2 neutrons per square centimeterNDEnondestructive examination NEDPNuclear Engineering Design Procedure NEINuclear Energy Institute NEILNuclear Electric Insurance Limited NEPANational Environmental Policy Act of 1969 NFPANational Fire Protection Association NMCAnoble metal chemical application NPSnominal pipe size xviiiNRCU.S. Nuclear Regulatory CommissionNSRnon-safety-related NSSSnuclear steam supply system NUREGU.S. Nuclear Regulatory Commission Regulatory Guide O 2 oxygenOCCWopen-cycle cooling water OEoperating experience OFSorificed fuel supports OIopen itemPBpressure boundaryPERProblem Evaluation Report PFMprobabilistic fracture mechanics PTpenetrant testing PTSpressurized thermal shock PUARPlant Unique Analysis Report PVCpolyvinyl chloride PWpipe whip restraint PWRpressurized water reactor PWSCCprimary water stress corrosion crackingQAquality assurance RAIrequest for additional informationRBCCWreactor building closed cooling water RBMrod block monitor RCICreactor core isolation cooling RCPBreactor coolant pressure boundary RCSreactor coolant system RCWraw cooling water RGregulatory guide RHrelative humidity RHRresidual heat removal RHRSWresidual heat removal service water RPVreactor pressure vessel RPVIIreactor pressure vessel internals inspection RSWraw service water RTreference temperature
 
RT NDT reference temperature nil ductility transitionRVreactor vessel RVIreactor vessel internal RWCUreactor water cleanupSBFstress-based fatigueSBOstation blackout SCstructure and component SCCstress corrosion cracking SCV steel containment vessel xixSERSafety Evaluation ReportSGTstandby gas treatment SIsurveillance instruction SILService Information Letter SLCstandby liquid control SMPStructures Monitoring Program
 
SO 2 sulfur dioxideSOCstatement of consideration SOERSignificant Operating Experience Report SPshelter/protection SPPstandard program and process SRsafety-related SRMsource range monitor SRPStandard Review Plan SRP-LRStandard Review Plan for Review of License Renewal Applications for Nuclear Power PlantsSRVsafety relief valve SSstainless steel or structural support or systems and structures SSAsafe shutdown analysis SSCsystem, structure, and component SSEsafe shutdown earthquakeTItechnical instructionTIPtraversing in-core probe TLAAtime-limited aging analysis TStechnical specification TVATennessee Valley Authority TVANTennessee Valley Authority NuclearUFSARupdated final safety analysis reportUNIDunique component identifier USASUSA standard USEupper-shelf energy UTultrasonic testing UVultra violetVvoltVFLDvessel flange leak detection VIPvessel and internals projectWOwork order XLPEcross-linked polyethylene xx THIS PAGE IS INTENTIONALLY LEFT BLANK 1-1 SECTION 1 INTRODUCTION AND GENERAL DISCUSSION
 
===1.1 Introduction===
This document is a safety evaluation report (SER) on the application for license renewal (LR) for the Browns Ferry Nuclear Plant (BFN), as filed by Tennessee Valley Authority (TVA or the
 
applicant). By letter dated December 31, 2003, TVA submitted its application to the U.S.
 
Nuclear Regulatory Commission (NRC or the Commission) for renewal of the BFN operating
 
licenses for an additional 20 years. The NRC staff (the staff) prepared this report, which
 
summarizes the results of its safety review of the renewal application for compliance with the
 
requirements of Title 10, Part 54, of the Code of Federal Regulations , (10 CFR Part 54),"Requirements for Renewal of Operating Licenses for Nuclear Power Plants." The NRC license
 
renewal project managers for the BFN license renewal review are Ram Subbaratnam and Yoira
 
Diaz-Sanabria. Mr. Subbaratnam can be contacted by telephone at 301-415-1478 or by
 
electronic mail at rxs2@nrc.gov; Ms. Diaz-Sanabria can be contacted by telephone at
 
301-415-1594 or by electronic mail at yks@nrc.gov. Alternatively, written correspondence may be sent to the following address:
License Renewal and Environmental Impacts Program U.S. Nuclear Regulatory Commission
 
Washington, D.C. 20555-0001
 
Attention: Ram Subbaratnam, or Yoira Diaz-Sanabria, Mail Stop 0-11-F1 In its December 31, 2003, submittal letter, the applicant requested renewal of the operating licenses issued under Section 104b (Operating License Nos. DPR-33, DPR-52, and DPR-68) of
 
the Atomic Energy Act of 1954, as amended, for BFN Units 1, 2, and 3 for a period of 20 years
 
beyond the current license expiration dates of midnight December 20, 2013, for Unit 1; midnight
 
June 28, 2014, for Unit 2; and midnight July 2, 2016 for Unit 3. The BFN units are located on the
 
north shore of Wheeler Reservoir in Limestone County, Alabama, at Tennessee River Mile 294.
 
The site is approximately 30 miles west of Huntsv ille, Alabama; it is also 10 miles northwest of Decatur, Alabama and 10 miles southwest of Athens, Alabama. The NRC issued the
 
construction permits for Unit 1 on May 10, 1967; for Unit 2 on May 10, 1967; and for Unit 3 on
 
July 31, 1968. The staff issued the operating licenses for Unit 1 on December 20, 1973; for
 
Unit 2 on June 28, 1974; and for Unit 3 on July 2, 1976. All of the units consist of a Mark I
 
boiling water reactor (BWR) with a nuclear steam supply system supplied by General Electric Corporation. The balance of each of the plants was originally designed and constructed by TVA.
 
Unit 1 licensed power output is 3293 megawatt thermal (MWt), with a gross electrical output of
 
approximately 1100 megawatt electric (MWe).
Units 2 and 3 licensed power output is 3458 MWt, with a gross electrical output of approximately 1155 MWe. The updated final safety
 
analysis report (UFSAR) contains details concerning the plant and the site. The units operated
 
from the original licensing until 1985 when they we re voluntarily shut down by the applicant to address management and technical issues. The applicant then implemented a comprehensive nuclear performance plan to correct the deficiencies that led to the shutdown. This plan included
 
changes in management, programs, processes and procedures, as well as extensive equipment refurbishment, replacement, and modifications. Unit 2 was subsequently restarted in 1991, and 1-2 Unit 3 followed in 1995. In the early 1990s, the applicant decided to defer restart of Unit 1.
Unit 1 is currently in a shutdown status.
The license renewal process consists of two concurrent reviews - a technical review of safety issues and an environmental review. The NRC regulations found in 10 CFR Parts 54 and 51, respectively, set forth the requirements against which license renewal applications are
 
reviewed. The safety review for the BFN license renewal is based on the applicant's license
 
renewal application (LRA) and on the responses to the staff's requests for additional information (RAIs). The applicant supplemented and clarified its responses to the LRA and RAIs in audits, meetings, and docketed correspondence. Unless otherwise noted, the staff reviewed and
 
considered information submitted through December 31, 2005. The public may view the LRA
 
and all pertinent information and materials, including the UFSAR mentioned above, at the NRC
 
Public Document Room, located in One White Flint North, 11555 Rockville Pike (first floor),
Rockville, MD 20852-2738 (301-415-4737/800-397-4209), and at the Athens-Limestone Public
 
Library, 405 South Street East, Athens, AL, 35611. In addition, the public may find the BFN
 
Units 1, 2, and 3 LRA, as well as materials related to the license renewal review, on the NRC
 
website at www.nrc.gov.
This SER summarizes the results of the staff's safety review of the BFN LRA and describes the technical details considered in evaluating the safety aspects of the units' proposed operation for
 
an additional 20 years beyond the term of the current operating licenses. The staff reviewed the
 
LRA in accordance with NRC regulations and the guidance provided in NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR), dated July 2001.
SER Sections 2 through 4 address the staff's review and evaluation of license renewal issues that it has considered during the review of the application. Section 5 is reserved for the report of
 
the Advisory Committee on Reactor Safeguards (ACRS). The conclusions of this report are in
 
Section 6.
SER Appendix A is a table that identifies the applicant's commitments associated with the renewal of the operating licenses. Appendix B provides a chronology of the principal
 
correspondence between the NRC and the applicant related to the review of the application.
 
Appendix C is a list of principal contributors to the SER. Appendix D is a bibliography of the
 
references used in support of the review.
In accordance with 10 CFR Part 51, the staff prepared a plant-specific supplement to the Generic Environmental Impact Statement (GEI S). This supplement discusses the environmental considerations related to renewing the licenses for BFN Units 1, 2, and 3. The staff issued (draft) Supplement 21 to NUREG-1437, "Generic Environmental Impact Statement for License
 
Renewal of Nuclear Plants: Regarding Browns Ferry Nuclear Plant, Units 1, 2, and 3: Draft
 
Report for Comment," on December 3, 2004. The final report was issued on June 23, 2005.
1-31.2  License Renewal Background Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating licenses for commercial power reactors are issued for 40 years. These licenses can be renewed
 
for up to 20 additional years. The original 40-year license term was selected on the basis of
 
economic and antitrust considerations, rather than on technical limitations; however, some
 
individual plant and equipment designs may have been engineered on the basis of an expected
 
40-year service life.
In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear power plant aging. This workshop led the NRC to establish a comprehensive program plan for nuclear
 
plant aging research. On the basis of the results of that research, a technical review group
 
concluded that many aging phenomena are r eadily manageable and do not pose technical issues that would preclude life extension for nuclear power plants. In 1986, the staff published a
 
request for comment on a policy statement that would address major policy, technical, and
 
procedural issues related to license renewal for nuclear power plants.
In 1991, the staff published the license renewal rule in 10 CFR Part 54 (the Rule). The staff participated in an industry-sponsored demonstration program to apply the Rule to a pilot plant
 
and to gain experience necessary to develop im plementation guidance. To establish a scope of review for license renewal, the Rule defined age-related degradation unique to license renewal;
 
however, during the demonstration program, the st aff found that adverse effects of aging occur to plant systems and components and the effects are managed during the period of initial
 
license. In addition, the staff found that the scope of the review did not allow sufficient credit for
 
existing programs, particularly the implementation of the Maintenance Rule, which also
 
manages plant-aging phenomena. As a result, the staff amended the license renewal rule in
 
1995. The amended 10 CFR Part 54 established a regulatory process that is simpler, more
 
stable, and more predictable than the previous license renewal rule. In particular, the staff
 
amended 10 CFR Part 54 to focus on managing the adverse effects of aging rather than on
 
identifying age-related degradation unique to license renewal. The staff initiated these rule
 
changes to ensure that important systems, st ructures, and components (SSCs) will continue to perform their intended functions during the period of extended operation. In addition, the revised
 
Rule clarified and simplified the integrated plant assessment (IPA) process to be consistent with
 
the revised focus on passive, long-lived structures and components (SCs).
In parallel with these efforts, the staff pursued a separate rulemaking effort and developed an amendment to 10 CFR Part 51 to focus the scope of the review of environmental impacts of
 
license renewal and fulfill the NRC's responsibilities under the National Environmental Policy
 
Act of 1969 (NEPA).1.2.1  Safety Review License renewal requirements for power reactors are based on two key principles:  1.The regulatory process is adequate to ensure that the licensing bases of all currently operating plants provide and maintain an acceptable level of safety, with the possible
 
exception of the detrimental effects of aging on the functionality of certain SSCs, as well
 
as a few other safety-related (SR) issues, during the period of extended operation; 1-4  2.The plant-specific licensing basis must be maintained during the renewal term in the same manner and to the same extent as during the original licensing term.
In implementing these two principles, 10 CFR 54.4 defines the scope of license renewal as including those SSCs (1) that are SR; (2) whose failure could affect SR functions; and (3) that
 
are relied on to demonstrate compliance with the NRC's regulations for fire protection (FP),
environmental qualification (EQ), pressurized thermal shock (PTS), anticipated transient without
 
scram (ATWS), and station blackout (SBO).
Pursuant to 10 CFR 54.21(a), an applicant for a renewed license must review all SSCs that are within the scope of the Rule to identify SCs that are subject to an aging management review (AMR). Those SCs that are subject to an AMR perform an intended function without moving
 
parts or without a change in configuration or properties, and are not subject to replacement
 
based on qualified life or specified time period. As required by 10 CFR 54.21(a), an applicant for
 
a renewed license must demonstrate that the effects of aging will be managed in such a way
 
that the intended function, or functions, of those SCs will be maintained, consistent with the
 
current licensing basis (CLB), for the period of extended operation; however, active equipment
 
is considered to be adequately monitored and maintained by existing programs. In other words, the detrimental effects of aging that may affect active equipment are more readily detectable
 
and can be identified and corrected through routine surveillance, performance monitoring, and
 
maintenance activities. The surveillance and ma intenance activities programs for active equipment, as well as other aspects of maintaining the plant design and licensing basis, are
 
required throughout the period of extended operation.
Pursuant to 10 CFR 54.21(d), each LRA is required to include a supplement to the FSAR (final safety analysis report) or UFSAR. This supplement must contain a summary description of the
 
applicant's programs and activities for managing the effects of aging and the evaluation of
 
time-limited aging analyses (TLAAs) for the period of extended operation.
License renewal also requires the identification and updating of the TLAAs. During the design phase for a plant, certain assumptions are made about the length of time the plant can operate.
 
These assumptions are incorporated into design calculations for several of the plant's SSCs. In
 
accordance with 10 CFR 54.21(c)(1), the applicant must either show that these calculations will
 
remain valid for the period of extended operation, project the analyses to the end of the period
 
of extended operation, or demonstrate that the effects of aging on these SSCs can be
 
adequately managed for the period of extended operation.
In 2001, the NRC developed and issued Regulatory Guide (RG) 1.188, "Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses". This RG endorses
 
Nuclear Energy Institute (NEI) 95-10, "Industry Guideline for Implementing the Requirements of
 
10 CFR Part 54 - The License Renewal Rule," which was issued in March 2001, by NEI.
 
NEI 95-10 details an acceptable method of implementing the license renewal rule. The staff also
 
used the SRP-LR to review this application.
In the LRA, BFN fully utilizes the process defined in NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," issued in July 2001. The GALL Report provides the staff with a
 
summary of staff-approved aging management progr ams (AMPs) for the aging of many SCs that are subject to an AMR. If an applicant commits to implementing these staff-approved
 
AMPs, the time, effort, and resources used to review an applicant's LRA can be greatly 1-5 reduced, thereby improving the efficiency and effectiveness of the license renewal review process. The GALL Report summarizes the aging management evaluations, programs, and activities credited for managing aging for most of the SCs used throughout the industry. The
 
report also serves as a reference for both applicants and staff reviewers to quickly identify those
 
AMPs and activities that the staff determined can provide adequate aging management during
 
the period of extended operation.
 
====1.2.2 Environmental====
Review Title 10, Part 51, of the Code of Federal Regulations (10 CFR Part 51) governs environmental protection regulations. In December 1996, the staff revised the environmental protection
 
regulations to facilitate the environmental review for license renewal. The staff prepared a
 
"Generic Environmental Impact Statement (GEI S) for License Renewal of Nuclear Plants"(NUREG-1437, Revision 1) to document its eval uation of the possible environmental impacts associated with renewing licenses of nuclear pow er plants. For certain types of environmental impacts, the GEIS establishes generic findings that are applicable to all nuclear power plants.
 
These generic findings are codified in Appendix B to Subpart A of 10 CFR Part 51. Pursuant to
 
10 CFR 51.53(c)(3)(i), an applicant for license renewal may incorporate these generic findings
 
in its environmental report. In accordance with 10 CFR 51.53(c)(3)(ii), an environmental report
 
must also include analyses of those environmental impacts that must be evaluated on a
 
plant-specific basis (i.e., Category 2 issues).
In accordance with NEPA and the requirements of 10 CFR Part 51, the staff performed a plant-specific review of the environmental im pacts of license renewal, including whether new and significant information existed that the GEIS did not consider. As part of its scoping
 
process, the staff held a public meeting on April 1, 2004, in Athens, Alabama to identify
 
environmental issues specific to the plant. The NRC's draft plant-specific Supplement 21 to the
 
BFN GEIS, which was issued on December 1, 2004, documents the results of the
 
environmental review and includes a preliminary recommendation with respect to the license
 
renewal action. The staff held another public meeting on January 25, 2005, in Athens, Alabama, to discuss the draft plant-specific Supplement 21 to the GEIS. After considering comments on
 
the draft, the staff published a final, plant-specific supplement to the GEIS separately from this
 
report on June 23, 2005.1.3  Principal Review Matters1.3.1  Operating Experience for BFN Unit 1 in Satisfying the Intent of the License Renewal Rule 1.3.1.1  Regulatory Framework Section 54.17(c) of 10 CFR states that an application for a renewed license may not be submitted earlier than 20 years before the expirati on of the operating license currently in effect.
The operating license for BFN Unit 1 expires on December 20, 2013; for Unit 2, on June 28, 2014; and for Unit 3, on July 2, 2016. The license renewal application for Units 1, 2, and 3 was
 
submitted on December 31, 2003. Thus, all units met this regulatory requirement and no
 
plant-specific exemptions were required.
1-6 When 10 CFR Part 54 was published, the Commission originally determined that a 20-year period of plant-specific operating experience would allow adequate assessment of any age-
 
related degradation of plant structures, systems, and components. The statement of
 
consideration (SOC) hence implied an intent of a 20-year threshold limit to ensure that
 
substantial operating experience is accumulated by licensees before the submittal of license
 
renewal applications. From that consideration, BFN Unit 1's 10-year operating history does not
 
entirely meet that intent. The Advisory Committee on Reactor Safeguards (ACRS or the
 
Committee), in an interim report dated October 19, 2005, on the safety aspects of the license
 
renewal application for BFN Units 1, 2, and 3, commented that 10 years of plant-specific
 
operating experience for BFN Unit 1, by itself, does not fully meet the intent of the license
 
renewal rule. TVA, in its response dated November 16, 2005, submitted for the Committee's
 
consideration the following information in support of its claim that Unit 1 meets the intent of the
 
Rule.1.3.1.2  Collective Operating Experience of the Three BFN Units BFN Unit 1 was licensed and began initial operation in 1973. Unit 2 began operation in 1974.
Units 1 and 2 operated until March 22, 1975, at which time both units were shut down due to a
 
fire in the Unit 1 reactor building. Units 1 and 2 resumed operation in 1976, and Unit 3 began
 
initial operation in 1977. All three units were operated until March 1985, at which time the
 
applicant voluntarily shut them down to address regulatory and management issues.
Following successful resolution of the management issues and the Unit 2 and common regulatory issues, Unit 2 was restarted on May 23, 1991. Unit 3 remained in a layup/recovery
 
mode for approximately 10 years and, following resolution of the Unit 3 regulatory issues, Unit 3
 
was restarted on November 19, 1995. Both Units 2 and 3 have operated with high capacity
 
factors into the present time. In the early 1990s, the applicant decided to defer the restart of
 
Unit 1.On May 16, 2002, the applicant announced the Unit 1 Restart Project. As part of the restart project, the applicant is performing the same restart programs and implementing the same
 
modifications that were previously completed on Units 2 and 3. At restart, Unit 1 will be
 
operationally the same as Units 2 and 3. Based only on the periods of operation as of 2005, Unit 1 has operated for approximately 10 calendar years, Unit 2 has operated for approximately
 
23 calendar years and Unit 3 has operated for approximately 18 calendar years.
All three BFN units share common facilities, materials, and environments. The three units are identical General Electric BWR 4 reactors with Mark I containments. TVA designed and constructed the units to be materially and operationally identical, with identical systems, components, materials, and environments. For a given power level, the system process conditions (e.g., pressure, temperatures, moisture content, chemical properties, flow rates, velocities, etc.) are identical. There is one UFSAR for the three units. Operating procedures and
 
Technical Specifications are nearly identical. Due to outage scheduling, small unit differences
 
may exist for short periods of time but are eliminated as modifications are installed on other
 
units during subsequent unit outages. Thus, over 51 years of operating experience is
 
accumulated collectively by the three units and this collective experience has been used to
 
support the preparation of the three-unit license renewal application. Addressing stakeholders'
 
questions when the Rule was published in 1991, the SOC states that the licensees and the
 
NRC can substitute nuclear industry operating ex perience for plant-specific experience, and the 1-7 staff need not limit its safety finding to in formation developed solely from plant-specific experience of an applicant. Therefore, the collectiv e 51 years experience is sufficient to support the renewal of the BFN Unit 1 operating license, because the Unit 2 operating experience, along
 
with the experience during the ten-year extended layup and subsequent operation of BFN Unit
 
3, applies to Unit 1. Specifically, in pursuing license renewal for BFN Unit 1, TVA has relied not
 
only on Unit 1's CLB, including the specific changes in Appendix F of the LRA, but also on Unit
 
1's plant-specific operating experience, the operating experience gained from BFN Units 2 and
 
3, and relevant industry-wide operating experience. This experience base satisfies and is
 
consistent with the regulatory requirements and intent of 10 CFR 54.17(c).
1.3.1.3  Corrective Action Program (CAP) Applicability In its submittal dated January 31, 2005, TVA stated that the three BFN units are essentially identical, and the application is not unit-specific regarding aging management programs. The
 
changes being implemented as part of Unit 1 restart activities are consistent with the changes
 
made previously to Units 2 and 3. AMPs are common for all three units based on their CLB.
 
Since at restart the Unit 1 licensing basis will be consistent with that of Units 2 and 3, the aging
 
management programs specified will be applicable to all three units. In addition to the
 
similarities between the Units 2 and 3 and Unit 1 licensing and design bases, specific programs
 
function such that relevant Units 2 and 3 operating experience is passed on to Unit 1. First, the
 
Corrective Action Program (CAP) applies to all TVA organizations involved in nuclear power
 
activities. This program is not unit specific and, as applicable, a condition identified at any BFN
 
unit is reviewed for generic implications potentially applicable to the other units. TVA also has
 
an administrative procedure for the review and dissemination of operating experience obtained
 
from both external and internal sources. This procedure requires screening of such information
 
for potential BFN applicability. This information is received from sources such as NRC
 
Information Notices, Institute of Nuclear Power Operations (INPO), nuclear steam supply
 
system (NSSS) vendor reports/notices, and in-house operating experience. If an item is determined to be applicable to BFN, then the information is addressed in the CAP. Thus, these
 
programs help ensure that relevant operating ex perience (OE) is applied to all three units.1.3.1.4  Aging Mechanism Similarities Between Units after Layup and Recovery During the collective periods of BFN operation, including recovery, the three units have experienced similar aging mechanisms. For exam ple, each unit has experienced the expected wear such as Flow Accelerated Corrosion (FAC), general corrosion, and microbiologically
 
induced corrosion (MIC). Applicable aging mechanisms for the passive plant features are
 
identified in LRA Section 3.0. The aging mechanisms for the passive plant features are well
 
known and are addressed by existing plant programs and procedures.
Since components and structures within the scope of AMRs for the three units contain the same materials and have experienced the same process conditions, all three units experience similar
 
aging effects. Unit 1 has been shut down since 1985. During the shutdown period, it
 
experienced aging effects analogous to those experienced on Units 2 and 3 during their
 
shutdown periods. In this regard, the applicant has utilized the OE gained from restarting and
 
operating Units 2 and 3, in recovering Unit 1, and has undertaken proactive steps to use the
 
aging mechanisms experienced during subsequent operation of Units 2 and 3 to determine the
 
necessary modifications to Unit 1 to preclude aging effects when possible. In many cases, the
 
aging mechanisms such as FAC had not resulted in significant wear in Unit 1; however, the 1-8 recovery effort has replaced the FAC-susceptible material with FAC-resistant material. The Unit 1 locations for replacements were expanded to address additional locations with
 
geometry/process conditions similar to Units 2 and 3 wear locations even if Units 2 and 3 had
 
not experienced significant wear in all similar locations. For example, if Unit 2 had experienced wear at one elbow, but not at two other elbows of similar material/geometry/process conditions, the Unit 1 restart scope included all 3 locations. The Unit 1 recovery design changes have not
 
resulted in the installation of types of material different from those present in Units 2 and 3.
 
Thus, during the collective periods of BFN operation, including recovery, the three units have
 
experienced similar aging mechanisms and will be appropriately managed during the period of extended operations.
1.3.1.5  Plant Upgrades As part of the recovery of Units 2 and 3, TVA implemented various plant upgrades (i.e., design changes) in response to regulatory issues and/or to improve plant operating characteristics.
 
This upgrade experience has been brought to bear in the Unit 1 recovery effort. For example, as
 
part of the recovery of Units 2 and 3, TVA replaced piping that was susceptible to intergranular
 
stress corrosion cracking (IGSCC). Similar design changes are being installed on Unit 1 as part
 
of the recovery process. IGSCC-susceptible piping in the reactor recirculation, residual heat
 
removal (RHR), reactor water cleanup (RWCU), and core spray (CS) systems on Unit 1 is being
 
replaced using materials that are resistant to IGSCC. (Also, see the beginning of SER Section
 
3.7)The applicant stated that it has effectively managed aging through various programs and has replaced and upgraded the plant to manage the effe cts of aging. For example, the systems susceptible to FAC are monitored in accordance with EPRI guidelines (LRA Section B.2.1.15, SER Section 3.0.3.2.9). Piping on Units 2 and 3 is monitored for FAC-induced wear and
 
replaced as needed. In many cases, the piping has been replaced with FAC-resistant chrome
 
molybdenum piping (LRA Section B.2.1.15, SER Section 3.0.3.2.9). Reactor vessel components
 
such as the shroud, vessel welds, jet pumps, core plate, and top guide are inspected by
 
accepted industry standards such as the Boiling Water Reactor Vessel Internals Program (BWRVIP) and repairs/replacements performed as required (LRA Section B.2.1.12, SER
 
Section 3.0.3.2.7). Raw water piping that is used to transfer heat from SR systems to the
 
ultimate heat sink is managed by the Open Cycle Cooling Water System Program (LRA Section B.2.1.17, SER Section 3.0.3.2.11). The primary containment liner is inspected in accordance
 
with American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section XI, Subsection IWE for steel containments (Class MC) requirements (LRA Section
 
B.2.1.31, SER Section 3.0.3.1.9). As explained in the LRA, these same programs are used on
 
all three units.
1.3.1.6  Inspections/Programs Expanded to Proactively Prevent Age Related Wear In its submittal dated November 16, 2005, TVA stated that the Unit 1 inspections/programs for other aging mechanisms have been expanded to pr oactively prevent age-related wear. The scope of replacement of IGSCC-susceptible piping is significantly larger in Unit 1 than in Units 2
 
or 3; thus, Unit 1 will contain a significantly larger scope of new pipe that has no pre-existing
 
aging effects. Since similar materials and geometry were used in Unit 1 for the expanded scope, there were no new aging mechanisms introduced. In addition, the Unit 1 systems that perform a
 
required function in the defueled condition, or that directly support the operation of  Unit 2 or 1-9 Unit 3, have been continuously operated and maintained under applicable Technical Specifications and plant programs since shutdown in 1985. This OE has been factored into the
 
LRA. Examples of these piping systems incl ude portions of fuel pool cooling and cleanup (FPC), control rod drive (CRD), raw cooling water (RCW), reactor building closed cooling water (RBCCW), RHR, residual heat removal service water (RHRSW), EECW, and control air systems. The applicant has maintained the Unit 1 systems in a physical condition during shutdown similar to those of Units 2 and 3 during their shutdown periods. The internal operating conditions (e.g.,
water chemistry, flow rate, temperature, etc.) for these systems are the same as those found in
 
the operating units. These systems have experi enced the same aging mechanisms and rates as experienced by the similar Units 2 and 3 system s for shutdown conditions. The Units 1, 2, and 3 reactor buildings are one continuous structure, and the external operating environments of the
 
systems are the same. Even though Unit 1 was in an extended outage, the overall
 
environmental conditions affecting external surfaces in Unit 1 were maintained consistent with
 
those of Units 2 and 3. Unit 1 had the normal ventilation systems in service, and equipment was
 
maintained to prevent system leakage so that the equipment was not subjected to aggressive
 
external conditions.
Other Unit 1 systems have been in a layup condi tion, and this prior layup experience has been applied to Unit 1 license renewal. For example, Unit 1 was placed in layup using the same
 
philosophy, processes, and conditions as used for Unit 3. Some piping systems (or portions of
 
piping systems) were placed into a "wet lay up" under TVA's Unit 1 layup procedure, which include RV, RCS, RWCU, portions of RHR, CS, and feedwater (FW) systems. The water
 
chemistry within these Unit 1 piping systems was monitored for compliance with the water
 
quality requirements. Thus, it would not be expected that a different aging mechanism or rate
 
would exist in wet layup compared to what woul d have occurred if the systems were in normal operation. The full scope of BWRVIP inspections have been performed on the Unit 1 reactor
 
vessel as part of the restart project. No adverse effects from the layup period were found, and
 
repairs/ replacements not related to layup will be performed as required. The reactor water
 
recirculation system and reactor water cleanup system piping, both large bore and small bore, have been replaced. The RHR and CS piping that was in wet layup has also been replaced. The
 
piping was replaced with the same materials that were used in Units 2 and 3. Ultrasonic
 
inspections of the FW piping have confirmed that the piping does not exhibit adverse effects
 
from the wet layup period. Thus, extensive la yup experience has been applied to the Unit 1 license renewal.
Some Unit 1 piping systems (or portions of piping systems) were drained and placed in dry layup, which included reactor core isolation cooling (RCIC), high pressure coolant injection (HPCI), main steam (MS), RHR, CS, and FW sy stems. The exterior of the system/component was maintained at nominal reactor or turbine buildings ambient conditions, which would have
 
been the same in Units 1, 2, and 3. Thus, the dry layup systems would have experienced aging at a rate less than or equal to that of the corresponding Unit 2/3 system.
Some Unit 1 systems were simply drained with no controlled environment. As a result, portions of two Unit 1 systems experienced accelerat ed aging. The accelerated aging of these systems was previously identified as part of the OE from the Unit 3 outage between 1985 and 1995.
 
These were portions of the Unit 1 RHRSW piping inside the reactor building and some small 1-10 bore raw cooling water piping. As explained in the beginning of SER Section 3.7, Units 2 and 3 OE was incorporated into Unit 1 aging management activities.
Thus, the applicant concluded that Unit 1 meets the Rule.1.3.2  License Renewal at Currently Licensed Power Level Part 54 of 10 CFR describes the requirements for renewing operating licenses for nuclear power plants. The staff performed its technical review of the LRA in accordance with Commission
 
guidance and the requirements of 10 CFR Part 54. Section 54.29 of 10 CFR sets forth the
 
standards for renewing a license. This SER describes the results of the staff's safety review.
 
The staff while performing the safety review limited its safety finding to matters related to the
 
CLB and at the currently authorized power levels for which the units are licensed. These power
 
levels are indicated in Section 1.1 of this SER's Introduction and General Discussion. Even
 
though the applicant's original submittal dated December 31, 2003, included a renewal request
 
at extended power uprate (EPU) conditions for the three BFN units, the applicant by its letter
 
dated January 7, 2005, requested decoupling the power uprate request from the LRA. In that
 
submittal the applicant requested that the staff complete the review based on the current
 
licensed power level for each of the three units and address separately the EPU conditions after
 
the renewed licenses are approved. Hence all the safety findings and staff evaluations apply to
 
the currently authorized power levels for which each of the BFN units are currently licensed.
 
====1.3.3 Integration====
of Unit 1 Restart Modification Ever since March 1985, Unit 1 has been on administrative hold and the applicant has committed not to restart Unit 1 without prior approval from the staff. The applicant is currently planning to
 
restart Unit 1 in 2007. The element unique to Unit 1 is that restart activities include modifying
 
the Unit 1 licensing basis to make it consistent with the CLB of Units 2 and 3. During the
 
meetings with the staff during 2003, it was agreed the applicant would identify in the LRA the
 
Unit 1 differences that will be eliminated when restart activities are completed. To highlight
 
these differences, information not yet applicable to Unit 1 was marked with bolded border. This
 
annotation methodology is consistent with previous multi-plant LRAs submitted to the staff. LRA
 
Appendix F describes each of these differences, its effect on the application, the schedule for
 
resolution, and provides references to application sections affected. This enables the applicant
 
to submit an LRA based on the CLB for all three units, as well as to identify Unit 1 restart
 
activities relevant to the LRA. The changes are being implemented as part of Unit 1 restart
 
activities consistent with the changes made previously to Units 2 and 3. Thus, the applicant
 
states that the BFN units are essentially identical, and the application is not unit-specific with
 
regard to AMPs or the AMRs. 1.3.4  Other Regulatory Requirements In 10 CFR 54.19(a), the NRC requires a license renewal applicant to submit general information. The applicant provided this general information in LRA Section 1, which it submitted
 
by letter dated December 31, 2003.
In 10 CFR 54.19(b), the NRC requires that each LRA include "conforming changes to the standard indemnity agreement, 10 CFR 140.92, Appendix B, to account for the expiration term 1-11 of the proposed renewed license." The applicant stated the following in the LRA regarding this issue: TVA requests that, as appropriate, conforming changes be made to the Article VII of the indemnity agreement, and item 3 of the Atta chment to the agreement, specifying the extension agreement until the expiration date of the renewed facility operating licenses
 
as sought in the application.
The staff intends to make conforming changes to the indemnity agreement so that the requirements of 10 CFR 54.19(b) will be met.
In 10 CFR 54.21, the NRC requires that each LRA must contain: (a) an IPA, (b) a description of any CLB changes that occurred during the staff review of the LRA, (c) an evaluation of TLAAs, and (d) an FSAR or a UFSAR supplement. Sections 3 and 4 and LRA Appendix B address the
 
license renewal requirements of 10 CFR 54.21(a), (b), and (c). LRA Appendix A contains the
 
license renewal requirements of 10 CFR 54.21(d).
In 10 CFR 54.21(b), the NRC requires that each year following submission of the LRA, and at least three months before the scheduled completion of the staff's review, the applicant must
 
submit an amendment to the renewal application that identifies any changes to the CLB of the
 
facility that materially affect the contents of the LRA, including the UFSAR supplement. The
 
applicant submitted an update to the LRA by letter dated January 31, 2005, which summarized
 
the changes to the CLB that have occurred during the staff's review of the LRA. This submission
 
satisfies the requirements of 10 CFR 54.21(b) and is still under staff review.
In accordance with 10 CFR 54.22, an applicant's LRA must include changes or additions to the technical specifications (TSs) that are necessary to manage the effects of aging during the
 
period of extended operation. In LRA Appendix D, the applicant stated that it had not identified
 
any TS changes necessary to support issuance of the renewed operating licenses for BFN.
The staff evaluated the technical information required by 10 CFR 54.21 and 10 CFR 54.22 in accordance with NRC regulations and the guidance provided by the SRP-LR. SER Sections 2, 3, and 4 document the staff's evaluation of the technical information contained in the LRA.
As required by 10 CFR 54.25, the ACRS will issue a report to document its evaluation of the staff's LRA review and associated SER. SER Section 5 will incorporate the ACRS report once it
 
is issued. SER Section 6 will document the findings required by 10 CFR 54.29.
The final plant-specific supplement to the GEIS was issued on June 23, 2005, and documents the staff's evaluation of the environmental information required by 10 CFR 54.23.
 
===1.4 Interim===
Staff Guidance The license renewal program is a living program. The NRC staff, industry, and other interested
 
stakeholders gain experience and develop lessons learned with each renewed license. The
 
lessons learned address the staff's performanc e goals of maintaining safety, improving effectiveness and efficiency, reducing regulatory burden, and increasing public confidence.
 
Interim staff guidance (ISG) is documented for use by the staff, industry, and other interested 1-12 stakeholders until it is incorporated into the license renewal guidance documents such as the SRP-LR and the GALL Report.
The following table provides the current set of ISGs issued by the staff, as well as the SER sections in which the staff addresses ISG issues.
ISG Issue (Approved ISG No.)PurposeSER Section GALL Report presents one acceptable way to manage
 
aging effects (ISG-1)This ISG clarifies that the GALL Report contains one
 
acceptable way, but not the
 
only way, to manage aging
 
for license renewal.
N/A SBO Scoping (ISG-2)The license renewal rule 10 CFR 54.4(a)(3) includes
 
10 CFR 50.63(a)(1)-SBO.
The SBO rule requires that a plant must withstand and
 
recover from an SBO event.
 
The recovery time for offsite
 
power is much faster than
 
that of EDGs.
The offsite power system should be included within the
 
scope of license renewal.
 
====2.1.3 Concrete====
AMP (ISG-3)Lessons learned from the GALL demonstration project
 
indicated that GALL is not
 
clear on whether concrete
 
requires an AMP.
3.5.2.2.8 ISG Issue (Approved ISG No.)PurposeSER Section 1-13 FP System Piping (ISG-4)This ISG clarifies the staff position for wall-thinning of
 
the FP piping system in GALL AMPs XI.M26 and XI.M27.The staff's new position is that there is no need to
 
disassemble FP piping, as
 
disassembly can introduce
 
oxygen to FP piping, which
 
can accelerate corrosion.
 
Instead, a non-intrusive
 
method, such as volumetric
 
inspection, should be used.
Testing of sprinkler heads should be performed at year
 
50 of sprinkler system
 
service life, and every 10
 
years thereafter.
This ISG eliminates the Halon/carbon dioxide system
 
inspections for charging
 
pressure, valve line-ups, and
 
the automatic mode of
 
operation test from GALL;
 
the staff considers these test
 
verifications to be operational
 
activities.
3.0.3.2.17 ISG Issue (Approved ISG No.)PurposeSER Section 1-14 Identification and Treatment of Electrical Fuse Holders (ISG-5)This ISG includes electrical fuse holders AMR and AMP (i.e., same as terminal blocks
 
and other electrical
 
connections).
The position includes only fuse holders that are not
 
inside the enclosure of active
 
components (e.g., inside of
 
switchgears and inverters).
Operating experience finds that metallic clamps (spring-loaded clips) have a
 
history of age-related failures
 
from aging stressors such as
 
vibration, thermal cycling, mechanical stress, corrosion, and chemical contamination.
The staff finds that visual inspection of fuse clips is not
 
sufficient to detect the aging
 
effects from fatigue, mechanical stress, and
 
vibration.
2.1.3.2.3 3.6.2.3.1 Scoping for fire protection equipment (ISG-7)This ISG provides clarification of the fire
 
protection systems, structures, and components
 
scoping to whether the scope
 
would expand to include (BTP) APSCB 9.5-1 2.1.3.1.2 The ISG Process (ISG-8)This ISG provides clarification and update to the
 
ISG process on Improved
 
License Renewal Guidance Documents.
N/A ISG Issue (Approved ISG No.)PurposeSER Section 1-15 Standardized Format for License Renewal
 
Applications (ISG-10)The purpose of this ISG is to provide a standardized
 
license renewal application
 
format for applicants.
N/A1.5  Summary of Open Items As a result of its review of the LRA, including additional information submitted to the staff through June 15, 2005, the staff identified the following open items (see below). An issue is
 
considered open if the applicant has not presented a sufficient basis for resolution. Each open
 
item (OI) has been assigned a unique identifying number.
OI-2.4-3: (Section 2.4 - Drywell Shell Corrosion)
Supplement 1 of Information Notice (IN) 86-99 indicates that, if leakage from the flooded reactor cavity is not monitored and managed, there is a potential for corrosion of the cylindrical portion
 
of drywell shell. As this corrosion would initiate in the non-inspectible areas of the drywell, it
 
cannot be monitored by IWE inspections. Moreover, this degradation of drywell shell can occur
 
even if there is very little water found in the sand-pocket area of the drywell. Thus, the reactor
 
building to drywell refueling seal becomes a non-safety-related (NSR) item that can affect the
 
integrity of the drywell shell (which is a pressure boundary component) during the period of
 
extended operation, and falls under the requirement of 10 CFR 54.4(a)(2). For two BWR plants, the staff accepted an alternative to managing the aging of the seal. The alternative is to
 
periodically perform ultrasonic testing (UT) of t he cylindrical portion of the drywell shell with an acceptable sampling program, as part of containment inservice inspection (ISI) program. After
 
reviewing the response to RAI 3.5-4 (in the applicant's letter dated January 31, 2005) related to
 
the operating experience of drywell shell corrosion at all three units, the staff came to the
 
conclusion that the applicant should manage the aging (leakage) of refueling seals, therefore, this is identified as OI 2.4-3.
The applicant responded to OI 2.4-3 by letter dated May 31, 2005. BFN did not include the refueling seals at the top of the drywell in the scope of license renewal and provided the
 
following technical basis for that conclusion: The drywell-to-reactor building refueling seal and
 
the reactor pressure vessel (RPV)-to-drywell refueling seal, in conjunction with the refueling
 
bulkhead, provide a watertight barrier to permit flooding above the RPV flange while preventing
 
water from entering the drywell. Providing a watertight barrier to permit flooding above the RPV
 
flange in support of refueling operations is an NSR function. In 10 CFR 54.4(a), the criteria that
 
determine whether plant systems, structures, and components are within the scope of license
 
renewal are set forth. The refueling seals do not satisfy any of the requirements set forth in
 
10 CFR 54.4(a)(1). The refueling seals are NSR, and they are not relied upon to remain
 
functional during design basis events. Thus, the refueling seals are not brought within the scope
 
of license renewal by 10 CFR 54.4(a)(1).
1-16 In a letter dated November 16, 2005, the applicant stated that for Unit 1 it  will perform one-time confirmatory ultrasonic thickness measurements on the vertical cylindrical area immediately below the drywell flange. For Units 2 and 3, it will perform the same testing in the portion of the cylindrical section of the drywell in a region where the liner plate is 0.75 inches thick. This will provide a bounding condition since the nominal thickness of the wall in this region has the least margin. The applicant committed to perform these ultrasonic thickness measurements prior to the Unit 1 restart, and prior to the period of extended operation for Units 2 and 3. The staff found this acceptable; therefore, OI 2.4-3 is closed.
OI-4.7.7: (Section 4.7.7 - Stress Relaxation of the Core Plate Hold-Down Bolts)
In LRA Section 4.7.7, the loss of preload of the core plate hold-down bolts due to thermal and irradiation effects was evaluated in accordance with the requirements of 10 CFR 54.21(c)(1)(ii).
 
For the 40-year lifetime, the Boiling Water Reactor Vessel and Internals Project (BWRVIP)-25
 
concluded that all core plate hold-down bolts will maintain some preload throughout the life of
 
the plant. For the period of extended operation, the expected loss of preload was assumed to
 
be 20 percent, which bounds the original BWRVIP analysis that was prepared to bound the
 
majority of plants, including BFN units after operating for 20 additional years. With a loss of 20
 
percent in preload, the core plate will maintain sufficient preload to prevent sliding under both
 
normal and accident conditions. Based on this assumption, the applicant concluded that the
 
loss of preload is acceptable for the period of extended operation.
In RAIs 4.7.7-1, 4.7.7-2, and follow ups, the staff requested the applicant to demonstrate how the BWRVIP-25 analysis can be applied to the BFN units based on the configuration and the
 
geometry of core plate hold-down bolts and t he reactor environment (temperature and neutron fluence) assumed in the original report. In its letter dated September 6, 2005, the applicant
 
provided the vendor's plant-specific calculations that will validate the assumptions as stated
 
above. However, the staff found that the methodology used did not follow the staff's approved
 
BWRVIP-25 analysis; therefore, it requested additional information. In its letter dated November
 
16, 2005, the applicant provided supplemental responses and identified several of the staff's
 
concerns raised during a teleconference on October 18, 2005. The applicant took the staff's comments under advisement and committed to perform a plant-specific analysis consistent with
 
BWRVIP-25. This analysis will be submitted for the staff's review two years prior to the period of
 
extended operation. The staff considers this acceptable; therefore, OI 4.7.7 is closed.
OI-3.0-3 LP
: (Section 3.0 - B.2.1.42, Unit 1 Periodic Inspection Program)
During the 526 th meeting of the Advisory Committee on Reactor Safeguards, October 6-7, 2005, the ACRS  reviewed the LRA for the BFN Units 1, 2, and 3, and the associated SER with open
 
items prepared by the staff. Though the Committee agreed with the staff that periodic
 
inspections of systems and components that we re not replaced are appropriate and necessary, it was not clear which systems will be included in the scope of the Unit 1 Periodic Inspection
 
Program, since no further attributes of this future program have been provided in the SER. The
 
main attributes of the program, including the intended scope, need to be defined in the final
 
SER. The Committee stated that periodic inspections are the most significant compensating
 
actions for the lack of plant-specific operating experience of BFN Unit 1 and It was not possible
 
to judge the adequacy of this important program since insufficient information has been
 
provided. As a result of the Committee's review, the staff elevated this issue from a confirmatory 1-17 item to an open item and requested the applicant to provide details of the periodic inspection program prior to issuance of the final SER. This is open item 3.0.3.
When the staff briefed the Committee on the SER with open items during the October 5-6, 2005 meeting, it omitted a description of this new plant-specific program called "B.2.1.42 - Unit 1
 
Periodic Inspection Program." The SER described the staff's review of information submitted to
 
the NRC through June 15, 2005, the cutoff date for consideration in the SER with open items.
 
Staff has since received details of this AMP titled, "B.2.1.42 - Unit 1 Periodic Inspection
 
Program." The staff review and evaluation of the program is included in this final version of the
 
SER in Section 3.0.3.3.5. This closes open item 3.0.3. 1.6  Summary of Confirmatory Items As a result of the staff's review of the LRA for BFN, including additional information and
 
clarifications submitted to the staff through June 15, 2005, the staff identified the following
 
confirmatory items (CIs). An issue is considered confirmatory if the staff and the applicant have
 
reached a satisfactory resolution, but the resolution has not yet been formally submitted to the
 
staff. Each CI has been assigned a unique identifying number. The items identified in this
 
section have been properly closed by the technical staff.
CI 3.3.2.35-1:
(Section 3.3 Bolting in Auxiliary Systems)
For auxiliary system closure bolting, the sta ff was concerned that cracking and loss of preload are not entirely addressed by either the American Society of Mechanical Engineers (ASME)
Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program or Bolting Integrity Program. Although ASME Section XI requires bolt torquing loads to be in accordance
 
with ASME Section III for replacement of Class 1 and 2 bolting, no bolt torquing requirements
 
are specified for Class 3 bolting, NSR bolting or bolting that is reused after being removed for
 
maintenance. The staff raised these issues in RAI 3.3.32.35-1.
The staff reviewed the applicant's response dated March 16, 2005, and found the response to be reasonable and acceptable. The applicant provided additional information to clarify that
 
cracking and loss of preload in bolting are being effectively managed. However, the response
 
did not provide the results of any self assessments, inspections, or maintenance activities, and
 
operating experience to determine if closure bolting in auxiliary systems was effectively managed at BFN for cracking and loss of preload. The staff discussed this issue with the
 
applicant in a teleconference, and the verification of this confirmatory item was addressed
 
during the AMP inspection performed on September 2005. In the inspection report, letter dated
 
November 8, 2005, the staff concluded that the bolting practices in BFN are functioning
 
adequately; therefore, CI 3.3.2.35-1 is closed.
CI-B.2.1.36 (Section B.2.1.36, Structures Monitoring Program)
The staff had a follow-up question in a May 4, 2005, teleconference regarding evaluation of inspection personnel qualification based on industry guidance, the American Concrete Institute (ACI) 349.3R-96 as stated in the Structures Monitoring Program. The staff stated that this
 
industry guidance alone will not be adequate to qualify the inspectors for the examination of
 
steel supports for the Structures Monitoring Program. The staff requested that the applicant
 
reevaluate the program element from previous st aff positions and submit the description for staff 1-18 review. In its response to a follow up to RAI B.2.1.33-1, by letter dated May 31, 2005, the applicant responded to the staff's question and committed (letter dated December 12, 2005) to manage the aging effects of Class MC supports under ASME Code Section XI Subsection IWF.
 
The applicant also agreed to include the inspector's qualification in accordance with the requirements of ASME Code Section XI Subsection IWF and not per the BFN Structures
 
Monitoring Program. The staff found this acceptable; therefore, CI-B.2.1.36 is closed.1.7  Summary of Proposed License Conditions As a result of the staff's review of the LRA, including subsequent information and clarifications
 
provided by the applicant, the staff identified four proposed license conditions.
The first license condition requires the applicant to include the UFSAR supplement required by 10 CFR 54.21(d) in the next UFSAR update, as required by 10 CFR 50.71(e), following the
 
issuance of the renewed licenses.
The second license condition requires the future activities identified in the FSAR supplement to be completed prior to entering the period of extended operation.
The third license condition requires that all capsules in the reactor vessel that are removed and tested meet the requirements of American Society for Testing and Materials (ASTM) E 185-82
 
to the extent practicable for the configuration of the specimens in the capsule. Any changes to the capsule withdrawal schedule, including spare capsules, must be approved by the staff prior
 
to implementation. All capsules placed in storage must be maintained for future insertion. Any
 
changes to storage requirements must be approved by the staff, as required by 10 CFR Part 50, Appendix H.
The fourth license condition is satisfactory completion of the thirteen Unit 1 restart commitments that are discussed in LRA Appendix F (see SER Section 2.6). Successful completion of these
 
restart activities provides a necessary regulatory framework for review of the LRA and is a staff
 
assumption fundamental throughout the staff safety review. When completed, the CLB of Unit 1
 
will be consistent with the CLB of Units 2 and 3. Completion of these activities is a condition to
 
be met prior to power operations of Unit 1.
2-1 SECTION 2 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW
 
===2.1 Scoping===
and Screening Methodology
 
====2.1.1 Introduction====
Title 10 of the Code of Federal Regulations , Part 54 (10 CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants," Section 54.21, "Contents of
 
Application - Technical Information," requires that each application for license renewal contain
 
an integrated plant assessment (IPA). Furthermore, the IPA must list and identify those
 
structures and components that are subject to an aging management review (AMR) from the
 
systems, structures, and components (SSCs) that are within the scope of license renewal in accordance with 10 CFR 54.4. LRA Sections 2.1.4 and 2.1.5 of the license renewal application (LRA) describe the applicant's process for identifying these structures and components (SCs)
 
and provide the scoping and screening results for those components, subcomponents, structural members, and commodity groups that are subject to an AMR in accordance with LRA
 
Section 3.0.
In LRA Section 2.1, "Scoping and Screening Methodology," the applicant described the scoping and screening methodology used to identify SSCs at the Browns Ferry Nuclear Plant (BFN)
 
within the scope of license renewal and SCs that are subject to an AMR. The staff reviewed the
 
applicant's scoping and screening methodology to determine if it meets the scoping
 
requirements stated in 10 CFR 54.4(a) and the screening requirements stated in 10 CFR 54.21.
In developing the scoping and screening methodology, the applicant considered the requirements of the Rule, the Statement of Consideration (SOC) for the Rule, and the guidance
 
presented by the Nuclear Energy Institute (NEI), "Industry Guideline for Implementing the
 
Requirements of 10 CFR Part 54 - The License Renewal Rule," Revision 3, March 2001, (NEI 95-10). In addition, the applicant considered the Nuclear Regulatory Commission (NRC)
 
staff's correspondence with other applicants and with the NEI in the development of this
 
methodology. Scoping and screening were performed as an integrated review at the
 
system/structure level. Screening was perfo rmed on a component-level basis, and the scoping results were reviewed and revised as required to be consistent with the screening results. The
 
short-lived passive components that could be ex cluded from an AMR on the basis of a qualified life or a specified replacement time period were identified and screened out as part of the AMR
 
process.2.1.2  Summary of Technical Information in the Application In LRA Sections 2.0 and 3.0, the applicant provided the technical information required by 10 CFR 54.21(a). In LRA Section 2.1, "Scoping and Screening Methodology," the applicant
 
described the process used to identify the SSCs that meet the license renewal scoping criteria
 
under 10 CFR 54.4(a), as well as the process used to identify the SCs that are subject to an
 
AMR as required by 10 CFR 54.21(a)(1). LRA Section 2.1.2 discusses the application of the
 
10 CFR 54.4(a) scoping criteria; Section 2.1.3 provides a discussion of the documentation that 2-2 was used to perform scoping and screening; and LRA Sections 2.1.4 and 2.1.5 describe the scoping and screening methodology.
Additionally, LRA Section 2.2, "Plant-Level Scoping Results"; Section 2.3, "Scoping and Screening Results: Mechanical Systems"; Section 2.4, "Scoping and Screening Results:
 
Structures"; and Section 2.5, "Scoping and Screening Results: Electrical and Instrumentation
 
and Control Systems" amplify the process the applicant used to identify the SCs that are subject
 
to an AMR. LRA Section 3, "Aging Management Review Results," contains the following
 
information:
* Section 3.1, "Aging Management of Reactor Vessel, Internals, and Reactor Coolant System"
* Section 3.2, "Aging Management of Engineered Safety Features Systems"
* Section 3.3, "Aging M anagement of Auxiliary Systems"
* Section 3.4, "Aging Management of Steam and Power Conversion Systems"
* Section 3.5, "Aging Management of Containment, Structures and Component Supports"
* Section 3.6, "Aging Management of Electrical and Instrumentation and Controls" LRA Section 4, "Time-Limited Aging Analyses," contains the applicant's identification and evaluation of time-limited aging analyses (TLAAs).2.1.2.1  Scoping Methodology In LRA Section 2.1, the applicant described the methodology used to scope systems and structures pursuant to the requirements of 10 CFR 54.4(a). The applicant identified differences
 
between the current licensing basis (CLB) for Unit 1 and the CLB for Units 2 and 3, and
 
documented them in LRA Appendix F. The applicant stated that the differences between CLBs
 
will be resolved before the restart of Unit 1, so that the CLB for Unit 1 will be consistent with
 
Units 2 and 3. The applicant's scoping methodology, as described in the LRA, is outlined in the
 
sections below.
2.1.2.1.1  Application of the Scoping Criteria in 10 CFR 54.4(a)
 
The applicant described the general approach to scoping SSCs that are safety-related (SR), nonsafety-related (NSR) affecting SR, or credited with demonstrating compliance with certain
 
regulated events in LRA Section 2.1.2, "Application of Scoping Criteria in 10 CFR 54.4(a)." The
 
scoping approaches specific to each of the three 10 CFR 54.4(a) scoping criteria are described
 
in the following sections.
Application of the Scoping Criteria in 10 CFR 54.4(a)(1). In LRA Section 2.1.2.1,"10 CFR 54.4(a)(1) - Safety-Related," the applicant discussed the scoping methodology as it
 
relates to SR criteria in accordance with 10 CFR 54.4(a)(1). With respect to the SR criteria, if
 
one or more of the three SR criteria were met, the applicant determined that the function was an
 
SR intended function, and included the corresponding SR SSCs within the scope of license
 
renewal that are relied upon to remain functional during and following/ a design basis event 2-3 (DBE) as defined in 10 CFR 50.49(b)(1) and are based on reviews of plant accident analyses and evaluations.
Application of the Scoping Criteria in 10 CFR 54.4(a)(2). In LRA Section 2.1.2.2,"10 CFR 54.4(a)(2) - Nonsafety-Related SSCs Whose Failure Could Prevent Satisfactory
 
Accomplishment of Safety-Related Functions," the applicant discussed the methodology used to
 
identify SSCs meeting the 10 CFR 54.4(a)(2) NSR license scoping criteria. Specifically, the
 
applicant considered the following SSCs to be in the scope of 10 CFR 54.4(a)(2):
* SCs, such as pipe whip restraints, that provide protection to SR SSCs to be in the scope of 10 CFR 54.4(a)(1) rather than 10 CFR 54.4(a)(2) SSCs
* Liquid-filled NSR SSCs directly connected to SR SSCs
* NSR SSCs that are not directly connected to SR structures such as, reactor buildings, primary containment structures
* NSR air/gas and heating, ventilation, and air conditioning (HVAC) systems that could prevent the satisfactory accomplishment of an SR function In LRA Section 2.1.2.2, the applicant described the methods and rationale used to scope each of the above categories of NSR SSCs in the LRA. The applicant's review encompassed the DBEs considered in these documents. The NSR SSCs already included within the scope of license renewal for 10 CFR 54.4(a)(3) were not identified for inclusion under 10 CFR 54.4(a)(2).
 
Application of the Scoping Criteria in 10 CFR 54.4(a)(3). In LRA Sections 2.1.2.3, "10 CFR 54.4 (a)(3) - The Five Regulated Events," and 2.1.3.4, "Specific Scoping Documents for Regulated
 
Events," the applicant discussed the methodology used to identify SSCs credited in performing
 
a function that demonstrates compliance with regulations for fire protection, environmental
 
qualification (EQ), anticipated transient without scram (ATWS), and station blackout (SBO)
 
pursuant to 10 CFR 54.4(a)(3) license renewal scoping criteria. The applicant did not address
 
pressurized thermal shock (PTS) because Browns Ferry units are boiling water type reactors to
 
which this criterion does not apply.
2.1.2.1.2  Documentation Sources Used for Scoping and Screening
 
In LRA Section 2.1.3, "Documentation Sources Used for Scoping and Screening," the applicant listed sources that were used as input during the license renewal scoping and screening
 
process:
* updated final safety analysis report (UFSAR)
* safe shutdown analysis (SSA) calculation
* Maintenance Rule documentation
* CLB and design-basis documents (design criteria documents and calculations, qualitative assessments and analyses, quantitative computations)
* controlled plant component database (also known as enterprise maintenance planning and control (EMPAC))
* site drawings 2-4 The applicant stated that these sources were used to identify the functions performed by plant systems and structures. These functions were then compared to the scoping criteria in
 
10 CFR 54.4(a)(1)-(3) to determine if the associated plant system or structure performed a
 
license renewal intended function. These sources were also used to develop the list of
 
structures and components subject to an AMR.
2.1.2.1.3  Plant and System Level Scoping
 
In LRA Section 2.1.4, "Scoping Methodology," the applicant stated that the scoping methodologies used to identify mechanical, electrical, and instrumentation and control (I&C)
 
systems and structures were described under the respective disciplines. In general, the
 
applicant created a list of systems and structur es from the EMPAC, site drawings, and the structures' design documents, UFSAR, Maintenance Rule documents, and other plant design
 
documents. The methodologies for individual disciplines are discussed below.
Mechanical Component Scoping. In LRA Section 2.1.4.1, the applicant described the scoping methodology for components within SR and NSR mechanical systems. For every mechanical
 
system, the applicant applied the following scoping process: (1) identify system intended
 
functions, (2) determine system evaluation boundary, and (3) create license renewal drawings.
 
The applicant used information from the SSA calculation, the UFSAR, and other applicable
 
documents to identify those systems that perform intended functions as defined in
 
10 CFR 54.4(a)(1).
 
A summary was prepared for each system that listed the identified system intended functions and the 10 CFR 54.4 criteria that caused the system to be within the scope of license renewal.
 
Those systems for which no functions were identified as satisfying any of the three scoping
 
criteria were classified as systems outside the scope of license renewal, and no further
 
evaluation was performed. After identifying the system intended functions, the applicant
 
established the system evaluation boundary, which i dentifies the portions of the system that are required to perform an intended function. Included in the evaluation boundary are the passive, long-lived components needed for the system to perform its intended functions. The components within the system evaluation boundary were reviewed according to the criteria of 10 CFR 54.4(a) used during evaluation of the system.
Electrical and Instrumentation and Control System Component Scoping. In LRA Section 2.1.4.2, the applicant described the scoping methodology for components in SR and NSR electrical and
 
I&C systems. Specifically, the applicant sele cted the electrical and I&C components from the EMPAC list and evaluated them against the 10 CFR 54.4(a) criteria. The applicant reviewed
 
NEI 95-10, and BFN documents such as plant drawings and EMPAC to determine the complete
 
set of electrical commodities installed at BFN. These electrical commodities were included in
 
the license renewal scope for evaluation using the spaces approach. The spaces approach
 
identified the electrical and I&C commodity groups that are installed in the plant and the limiting
 
environmental conditions for each group. The only exception to the spaces approach was in the
 
SBO offsite power restoration methodology. The applicant used the conventional system
 
evaluation methodology (i.e., mechanical system scoping) to identify the system intended functions and subsequent SCs within the scope of license renewal. As part of this review, the
 
applicant reviewed the SSA calculation, UFSAR descriptions, Maintenance Rule documents, CLB, and design-basis documents to determine the system's safety classification level, and to
 
identify the system intended functions.
2-5 Structural Component Scoping. In LRA Section 2.1.4.3, the applicant described the scoping methodology for components within SR and NSR structures. Specifically, the applicant stated
 
that the list of structures used for scoping was developed from the review of design drawings, design criteria document, and Maintenance Rule documentation, which include items such as
 
free-standing buildings and structures, primary containment shell, tank foundations, manholes, tunnels, duct banks, and earthen structures. The applicant relied on the design criteria
 
document for structures and the UFSAR to identify the safety classification of structures and structural components.
For review purposes, seismic Class I structures and structural components were considered SR. Structure functions were evaluated against the 10 CFR 54.4(a) criteria and structure
 
intended functions were identified. The structure interfaces were examined and, in those
 
instances where a failure of a structure could prevent a satisfactory accomplishment of any SR intended function or adversely impact other SR structures, that structure was identified and
 
included within the scope of license renewal. The applicant reviewed detailed structural
 
drawings for structures determined to be within the scope of license renewal to identify
 
structural components. For structures within the scope of license renewal, all structural
 
components required to support the intended functions were identified as within the scope of
 
license renewal.2.1.2.2  Screening Methodology In LRA Section 2.1.5, "Screening Methodology," the applicant described the process of identifying the structures and components that are subject to an AMR. The applicant stated that, in accordance with 10 CFR 54.21(a)(1)(i), the screening process used the industry guidance
 
contained in NEI-95-10, Revision 3, Appendix B, "Typical Structure, Component and Commodity
 
Groupings and Active/Passive Determinations for the Integrated Plant Assessment," to identify
 
SSCs from items within the scope of license renewal that require AMR. The identified SSCs
 
were then sorted into groups that (1) perform an intended function, as described in
 
10 CFR 54.4, without moving parts or without a change in configuration or properties; and (2)
 
those that are not subject to replacement based on a qualified life or specified time period.
 
Components were then evaluated to determine which were long-lived. Components were
 
considered long-lived unless specific plant documentation indicates the component is replaced
 
at intervals of less than forty years.
2.1.2.2.1  Mechanical Component Screening
 
In LRA Section 2.1.5.1, the applicant described the component screening for mechanical systems as a continuation of the component scoping activity. The applicant evaluated each component within the scope of license renewal to determine if it has a passive function. If a
 
component has a passive function that supports a system intended function, and if the
 
component was determined to be long-lived, then the component was considered subject to an
 
AMR. The applicant reviewed maintenance procedures, records, and vendor recommendations
 
to determine if a component is long- or short-lived.
2.1.2.2.2  Structural Component Screening
 
In LRA Section 2.1.5.3, the applicant described the methodology used to screen the structural components within the scope of license renewal. The screening methodology classified 2-6 in-scope structural components as passive consistent with the guidance found in NEI 95-10, Appendix B. In-scope structural components such as elastomers, which are subject to
 
replacement in specified intervals, were considered short-lived and were excluded from an AMR. The structural screening included certain st ructural components in electrical systems (e.g., cable trays) and mechanical systems (e.g., pipe supports).
2.1.2.2.3  Electrical and Instrumentation and Control System Component Screening Methodology In LRA Section 2.1.5.2, the applicant described the screening methodology for electrical and I&C components. The applicant had classified all electrical and I&C components within the
 
scope of license renewal based on the spaces approach, with the exception of components in
 
the SBO offsite power restoration flow path. Components were characterized as active or
 
passive, based on NEI 95-10, Appendix B, guidance. Long-lived commodity groups were
 
identified by using industry and BFN experience. The spaces approach identifies the electrical
 
and I&C commodity groups that are install ed in the plant and the limiting environmental conditions for each group. The spaces approach then determines if any area environment is
 
more severe than the limiting environment for the commodity group. If the area environment is more severe than a commodity group's limit, and if a component in the commodity group is actually located in the area, an AMR is required for that commodity group.
 
====2.1.3 Staff====
Evaluation The staff evaluated the LRA scoping and screening methodology in accordance with the guidance contained in Section 2.1, "Scoping and Screening Methodology," of U.S. Nuclear
 
Regulatory Commission Regulatory Guide (NUREG)-1800, "Standard Review Plan for Review
 
of License Renewal Applications for Nuclear Power Plants" (SRP-LR). The acceptance criteria
 
for the scoping and screening methodology review are based on the following regulations:
* 10 CFR 54.4(a), as it relates to the identification of plant SSCs within the scope of the Rule.
* 10 CFR 54.4(b), as it relates to the identification of the intended functions of plant SSCs determined to be within the scope of the Rule.
* 10 CFR 54.21(a)(1) and (a)(2), as they relate to the methods used by the applicant to identify plant structures and components subject to an AMR.
As part of the review of the applicant's scoping and screening methodology, the staff reviewed the activities described in the following sections of the LRA using the guidance contained in
 
the SRP-LR:
* Section 2.1, "Scoping and Screening Methodology," to verify that the applicant described a process for identifying SSCs that are within the scope of license renewal in
 
accordance with the requirements of 10 CFR 54.4(a)(1), (a)(2), and (a)(3),
* Section 2.2, "Plant-Level Scoping Results"; Section 2.3, "Scoping and Screening Results: Mechanical Systems"; Section 2.4, "Scoping and Screening Results:
 
Structures"; and Section 2.5, "Scoping and Screening Results: Electrical and
 
Instrumentation and Control Systems," to verify that the applicant described a process 2-7 for determining structural, mechanical, and electrical components that are subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1) and (a)(2).
In addition, the staff conducted a scoping and screening methodology audit at the Tennessee Valley Authority (TVA) corporate offices in Chattanooga, TN, from June 7 to 10, 2004. The focus
 
of the audit was to ensure that the applicant had developed and implemented adequate
 
guidance to conduct the scoping and screening of SSCs in accordance with the methodologies
 
described in the application and the requirements of the Rule. The staff reviewed
 
implementation procedures and engineering reports which describe the scoping and screening
 
methodology implemented by the applicant. In addition, the staff conducted detailed discussions
 
with the applicant on the implementation and control of the license renewal program and
 
reviewed administrative control documentation and selected design documentation used by the applicant during the scoping and screening process. The staff further reviewed a sample of
 
system scoping and screening results reports for the residual heat removal service water (RHRSW) system and the emergency equipment coo ling water (EECW) system to ensure that the methodology outlined in the technical evaluations was appropriately implemented and the
 
results were consistent with the CLB.2.1.3.1  Scoping Methodology The scoping evaluations for the Browns Ferry Nuclear LRA were performed by the applicant's license renewal project personnel. The staff conducted detailed discussions with the applicant's
 
license renewal project personnel and reviewed documentation pertinent to the scoping
 
process. The staff assessed whether the scoping methodology outlined in the LRA and
 
implementation procedures was appropriately implemented and whether the scoping results were consistent with CLB requirements.
2.1.3.1.1  Implementation Procedures and Documentation Sources Used for Scoping and Screening The staff reviewed the applicant's scoping and screening implementation procedures to verify that the process used to identify structures and components subject to an AMR was consistent
 
with the LRA and SRP-LR and that the applicant had appropriately implemented the procedural
 
guidance. Additionally, the staff reviewed the scope of CLB documentation sources used to
 
support the LRA development and the process used by the applicant to ensure that CLB
 
commitments has been appropriately considered during the scoping and screening process.
Scoping and Screening Implementation Procedures. The staff reviewed the following TVA scoping and screening methodology implementation procedures and engineering documents: 0-TI-346Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting0-TI-455Mechanical Technical Evaluations For License Renewal, Revision 2 0-TI-456Electrical Technical Evaluations For License Renewal 0-TI-457Civil Technical Evaluations For License Renewal 0-TI-458License Renewal Time Limited Aging Analyses, Revision 1 2-8NEDP-21Technical Evaluations for License Renewal, Revision 2 NEDP-4Q-list and UNID Control, Revision 7 NEDP-5Design Document Reviews SPP-3.1Corrective Action Program, Revision 6 SPP-9.6Master Equipment List, (MEL) Revision 6 In reviewing these procedures, the staff focused on the consistency of the detailed procedural guidance with information in the LRA and the various staff positions documented in the SRP-LR
 
and interim staff guidance documents. The staff found that the scoping and screening
 
methodology instructions were generally consistent with LRA Section 2.1 and were of sufficient
 
detail to provide the applicant with concise guidance on the scoping and screening
 
implementation process to be followed during the LRA activities.
In addition to the implementing procedures, the staff reviewed supplemental design information including design-basis documents, system draw ings, and selected licensing documentation, that the applicant relied on during the scoping and screening phases of the review. The staff found
 
these design documentation sources to be useful for ensuring that the initial scope of SSCs
 
identified by the applicant was consistent with the plant's CLB.
Sources of Current Licensing Basis Information. The staff reviewed the scope and depth of the applicant's CLB review to verify that the methodology was sufficiently comprehensive to identify
 
SSCs within the scope of license renewal and SCs requiring an AMR. As defined in
 
10 CFR 54.3(a), the CLB is the set of NRC requirements applicable to a specific plant and a
 
licensee's written commitments for ensuring compliance with, and operation within, applicable
 
NRC requirements and the plant-specific design basis that are docketed and in effect. The CLB
 
includes certain NRC regulations, orders, license conditions, exemptions, technical
 
specifications, design-basis information documented in the most recent UFSAR, and licensee
 
commitments remaining in effect from docketed licensing correspondence such as applicant
 
responses to NRC bulletins, generic letters (GLs
), and enforcement actions, as well as licensee commitments documented in NRC safety evaluat ions or licensee event reports. The applicant identified differences between the CLB for Unit 1 and the CLB for Units 2 and 3, and
 
documented them in LRA Appendix F.
The staff determined that LRA Section 2.1.3 provides a description of the CLB and related documents used during the scoping and screening process that is consistent with the guidance
 
contained in the SRP-LR and NEI 95-10. Specif ically, the applicant provided a comprehensive listing of documents that could be used to support scoping and screening evaluations. The
 
applicant noted that system descriptions and system intended functions had been identified
 
based on the review of the applicable sections of the UFSAR, Appendix B determinations, Maintenance Rule scoping document, and design and licensing basis documents.
Conclusion. Based on a review of information provided in LRA Section 2.1, a review of the applicant's detailed scoping and screening implementation procedures, and the results from the
 
scoping and screening audit, the staff concluded that the applicant's scoping and screening
 
methodology had considered a scope of CLB information generally consistent with the guidance
 
contained in the SRP-LR and NEI 95-10.
2-9 Quality Assurance Controls Applied to LRA Development. The staff reviewed the quality assurance controls used by the applicant to verify that they provided reasonable confidence that
 
the LRA scoping and screening methodologies had been adequately implemented. The
 
applicant chose not to credit the existing 10 CFR 50, Appendix B quality assurance program for
 
the development of the LRA. However, the applicant controlled the LRA development activities
 
as follows:
* Written procedures and guidelines governed implementation of the scoping and screening methodology.
* All final in-scope and screening information was developed by a lead technical staff member and independently reviewed by an additional technical staff member prior to
 
being reviewed and approved by the program manager.
* The applicant developed a formal database for documenting license renewal information identified during in-scope and screening evaluations. This database was controlled in
 
accordance with written instructions, and access to it was strictly controlled.
* The LRA was reviewed and approved by an independent expert committee comprised of experienced members of the TVA corporate engineering staff and BFN personnel.
* The applicant conducted two program peer reviews and one self-assessment of LRA activities to validate the implementation process and the technical accuracy of the
 
application.
* The applicant instituted a training program, which required all participants in LRA activities to be certified to perform LRA activities and to attend training on the use of
 
procedures, guidance documents, computer programs, and drawings.
Conclusion. The staff concluded that these quality assurance activities, which exceeded current regulatory requirements, provided additional assurance that LRA development activities were
 
performed consistently with the LRA descriptions.
Training for License Renewal Project Personnel. The staff reviewed the applicant's implemented training process to ensure the guidelines and methodology for the scoping and screening
 
activities would be performed in a consistent and appropriate manner. The applicant's LRA staff
 
consisted of several engineers and contractors who had gained previous license renewal
 
experience working on the Edwin I. Hatch LRA. The purpose of the training was to provide a
 
framework for ensuring that the staff assigned to the technical portion of the LRA acquired a
 
fundamental level of knowledge of the license renewal process and regulatory requirements.
 
BFN used the Nuclear Engineering Design Procedure (NEDP)-7, Engineering Support
 
Personnel Training, Revision 12, dated January 29, 2004, to impart training to all personnel
 
involved in the LRA activities. Other documents used in the training include NEDP-7
 
Qualifications Guides (QGs), Task-Specif ic QGs, License Renewal Program, NEDP-21, Technical Evaluation for License Renewal, the Code of Federal Regulations , and NEI 95-10, Industry Guidelines for Implementing the Requirements of 10 CFR Part 54 - The License
 
Renewal Rule.
The staff reviewed the completed qualification and training records of several of the applicant's license renewal staff, including both experienced and non-experienced members, who
 
performed scoping and screening activities. The staff did not identify any adverse findings.
2-10 Additionally, based on discussions with the applicant's license renewal personnel during the audit, the staff verified that the applicant's license renewal staff were knowledgeable
 
concerning the license renewal process requirements and the specific technical issues within
 
their areas of responsibility. The staff found that the applicant's license renewal training records
 
were considered quality-related records and that these records were accurate, comprehensive, and complete.
Conclusion. The results from the scoping and screening audit indicate that the applicant considered the information in the CLB for Units 1, 2, and 3 in developing the scoping and
 
screening methodology. The CLB documentation review methodology was capable of
 
identifying the intended functions of the SSCs in a manner consistent with the requirements of
 
10 CFR 54.4 and 10 CFR 54.21. In addition, the applicant applied appropriate quality controls
 
during the development of the application and adequately trained the applicable personnel. The
 
staff concluded that the applicant had considered all relevant information during the preparation
 
of the scoping and screening methodologies.
2.1.3.1.2  Application of the Scoping Criteria in 10 CFR 54.4(a)
 
The staff evaluated the application of the scoping criteria for the methodology for scoping SR-and NSR-related SSCs and SSCs relied upon to demonstrate compliance with regulated events
 
pursuant to 10 CFR 54.4(a). The results of the staff's evaluation are described below.
Application of the Scoping Criteria in 10 CFR 54.4(a)(1). Pursuant to 10 CFR 54.4(a)(1), the applicant must consider all SR SSCs that are relied upon to remain functional during and
 
following DBEs to ensure the following functions: (1) maintain the integrity of the reactor coolant
 
pressure boundary, (2) maintain the ability to shut down the reactor and maintain it in a safe
 
shutdown condition, or (3) maintain the capability to prevent or mitigate the consequences of
 
accidents that could result in potential offsite exposures comparable to those referred to in
 
10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2) or 10 CFR 100.11.
During the scoping and screening methodology audit, the staff questioned how non-accident DBEs, particularly DBEs that may not be described in the UFSAR, were considered during
 
scoping. The applicant responded by identifying the DBEs applicable to BFN, including external
 
hazards such as fire, earthquakes, flooding, wind and missiles, and high-energy line breaks.
 
Additional DBEs were evaluated in the SSA calculation that was used by the applicant as a
 
primary source for the purposes of identifying SSCs within the scope of license renewal. The
 
SSA calculation was reviewed by the staff and discussed with the applicant. The staff found that
 
the report contained a concise and detailed evaluation of approximately 35 events, and included
 
appropriate CLB documentation references to support the review. The staff concluded that the
 
applicant considered a scope of DBEs that was consistent with the guidance contained in the
 
SRP-LR.In addition, the staff evaluated the guidance documents governing the applicant's evaluation of SR SSCs: specifically, BFN standard department procedures; NEDP-5, "Design Document
 
Reviews," Revision 2; NEDP-21, "Technical Evaluations for License Renewal," Revision 2; and
 
license renewal instruction series 0-TI-455 through 458. Guidance was established for the
 
preparation, review, verification, and approval of the scoping evaluations to assure the
 
adequacy of the results of the scoping process. During the scoping and screening audit the staff
 
reviewed the guidance and discussed the scoping approach with the applicant. Specifically, the 2-11 staff reviewed a sample of the license renewal scoping results for the residual heat removal (RHR) system to provide additional assurance that the applicant adequately implemented its SR
 
scoping methodology. The system scoping sheet identified the RHR system as SR with
 
additional NSR systems supporting its operation.
The evaluation identified the RHR system as meeting several of the 10 CFR 54.4(a)(3) criteria including: (1) EQ, (2) fire protection, and (3)
 
SBO. All the system safety descriptions were listed, and the licensing basis calculations
 
supporting those determinations were appropriately referenced. The report identified the
 
cognizant license renewal staff members who prepared and verified the results. The applicant
 
documented the information on a scoping results form. The applicant created a license
 
boundary drawing in which every component in the system was identified by its unique component identifier (UNID) number, the description of the component, whether it was SR or
 
NSR, whether it supported any of the regulated events, and the commodity material group to
 
which it belonged (valve or pump etc.). The staff determined that the applicant identified and
 
used pertinent engineering and licensing information to support the scoping determinations for
 
the items sampled, and found the preparation, review, and approval of the scoping results to be
 
effective for the development and evaluation of SR functions and subsequent identification of
 
SSCs within the scope of license renewal.
The applicant reviewed the license renewal drawings in conjunction with physical drawings and component listings from EMPAC to determine the in-scope components that met the SR
 
scoping criterion. All components identified as SR using the SR classification field in the
 
EMPAC were considered for inclusion within the scope of the license renewal project. The
 
applicant noted that the EMPAC safety-classifica tion field was prepared many years ago using a definition for SR that was not necessarily the same as the definition of SR as described in the
 
Rule. The staff reviewed the safety classification criteria used to determine the EMPAC safety
 
classification to verify consistency with the 10 CFR 54.4(a)(1) criteria. The staff determined that
 
the nuclear SR definition used by the applicant in its safety classification program did not
 
include all the exposure limitations referenced in 10 CFR 54(a)(1)(iii). Specifically, procedures
 
BFN-50-739, "Classification of Structures, Systems, and Components, Revision 3," and
 
NEDP-4, "Q-list and UNID Control, Revision 7," did not include a reference to the offsite
 
exposure limitations contained in 10 CFR 50.67(b)(2) for use of an alternate source term (AST).
Based on the above, the staff identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The applicant
 
responded to the staff's request for additional information (RAI) as discussed below.
In RAI 2.1-1, dated July 30, 2004, the staff requested the applicant to provide additional information to describe the SR classification definitions that were used in developing the list of
 
SSCs for the license renewal scoping and screening process, and describe how the offsite
 
exposure limitations were factored into the LRA.
In its response, by letter dated September 3, 2004, the applicant stated:
Consistent with 10 CFR 54.4(a)(1)(iii), BFN utilized a definition of safety-related that incorporated potential offsite exposures as follows: "The capability to prevent or mitigate
 
the consequences of accidents which could result in potential offsite exposures
 
comparable to those referred to in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or
 
10 CFR 100.11, as applicable." The applicable regulation for BFN is 10 CFR 100.11.
 
10 CFR 50.34 applies to applications for a construction permit and as such is not 2-12 applicable to BFN. 10 CFR 50.67(b)(2) is applicable to plants revising their current accident source term to Alternative Source Term (AST). TVA has submitted a request for
 
an amendment to the BFN Units 1, 2, and 3 facility operating licenses supporting a full
 
scope application of the AST methodology. The application of AST is not approved by
 
NRC hence, 10 CFR 50.67(b)(2) is not applicable to BFN. The BFN safety-related
 
equipment classification and the SSCs included in the scope of license renewal continue
 
to be based on potential offsite exposures contained in 10 CFR 100. Based on a review
 
of TVA's AST submittal it is expected no new systems or component types will be added within the License Renewal scope that are not already identified in the application.
On September 27, 2004, the staff approved the applicant's license amendment request regarding AST per 10 CFR 50.67(b)(2) for offsite dose exposure as the CLB for BFN. Since the
 
definition of SR components as applied to the scoping of components in the LRA can be either
 
10 CFR 50.67(b)(2) or 10 CFR 100.11, as applicable, and the AST submittal did not add new
 
components within the LRA scope, it does not impact the SR definition. Hence the staff
 
concluded that, consistent with 10 CFR 54.4(a)(ii), BFN utilized a definition of SR that included
 
the capability to shut down the reactor and maintain it in a safe shutdown condition. The staff
 
determined that the applicant's response is acceptable. The staff's concern described in
 
RAI 2.1-1 is resolved.
Conclusion. The staff reviewed a sample of the license renewal database 10 CFR 54.4(a)(1) scoping results and discussed the methodology and results with the applicant's license renewal
 
project personnel. The staff verified that the applicant had identified and used pertinent
 
engineering and the CLB in order to determine the SSCs required to be within the scope of
 
license renewal in accordance with the 10 CFR 54.4(a)(1) criteria. On the basis of a review of
 
the applicant's methodology and evaluation of a sampling of scoping results and responses to
 
the staff's RAI, the staff concluded that the applicant's SR scoping methodology provided
 
reasonable assurance that SSCs meeting the scoping criteria of 10 CFR 54.4(a)(1) were
 
included within the scope of license renewal.
Application of the Scoping Criteria in 10 CFR 54.4(a)(2). Section 54(a)(2) of 10 CFR requires, in part, that the applicant consider all NSR SSCs whose failure could prevent satisfactory
 
accomplishment of any of the functions identified in paragraphs 10 CFR 54(a)(1)(i),
10 CFR 54(a)(1)(ii), or 10 CFR 54(a)(1)(iii) to be within the scope of the license renewal.
In addition, by letters dated December 3, 2001, and March 15, 2002, the NRC issued a staff position to the NEI, which described areas for applicants to consider and options it expects
 
applicants to use to determine which SSCs meet the 10 CFR 54.4(a)(2) criterion (i.e., all NSR
 
SSCs whose failure could prevent satisfactory a ccomplishment of any SR functions identified in paragraphs 10 CFR 54.4(a)(1)(i)-(iii)). The December 3, 2001, letter provided specific examples
 
of operating experience that identified pipe failure events (summarized in Information Notice (IN)
 
2001-09, "Main Feedwater System Degradation in Safety-Related ASME Code Class 2 Piping Inside the Containment of a Pressurized Water Reactor") and the approaches the staff
 
considers acceptable to determine which piping systems should be included within the scope of
 
license renewal based on the 10 CFR 54.4(a)(2) criterion. The March 15, 2002, letter, further
 
described the staff's expectations for the evaluation of non-piping SSCs to determine which
 
additional NSR SSCs are within the scope of license renewal. The position states that
 
applicants should not consider hypothetical failures, but, instead, should base their evaluation
 
on the plant's CLB, engineering judgment and analyses, and relevant operating experience. The 2-13 paper further describes operating experience as all documented plant-specific and industry-wide experience that can be used to determine the plausibility of a failure.
 
Documentation would include generic communications and event reports, plant-specific
 
condition reports, industry reports such as si gnificant operating experience reports (SOERs), and engineering evaluations.
As stated in the LRA, the applicant had included in the scope of license renewal NSR SSCs whose failure could prevent satisfactory accomplishment of any of the functions identified in
 
paragraphs 10 CFR 54.4(a)(1)(i)-(iii). The applicant identified SSCs satisfying criterion
 
10 CFR 54.4(a)(2) based on review of applicable CLB and engineering design bases and
 
design documents, plant-specific and industry operating experience, and industry guidance
 
documents.
The applicant documented the review of scoping activities in support of 10 CFR 54.4(a)(2) in an engineering report titled "10 CFR 54.4(a)(2) Scoping Methodology." The applicant discussed the
 
scoping methodology as it related to the NSR criteria in accordance with 10 CFR 54.4(a)(2).
 
With respect to the NSR criteria, the applicant stated that a review had been performed to
 
identify the NSR SSCs whose failure could prevent satisfactory accomplishment of the SR
 
intended functions identified in 10 CFR 54.4(a)(1).
As stated in the LRA, the applicant identified NSR SSCs whose failure could prevent satisfactory accomplishment of a safety func tion. The impacts of NSR system, structure, and component (SSC) failures were considered as either functional or spatial. In a functional failure, the failure of an SSC to perform its normal function impacts a safety function. In a spatial failure, a safety function is impacted by the loss of structural or mechanical integrity of an SSC in
 
physical proximity to an SR component.
Functional Failures of Nonsafety-Related SSCs. In general SSCs required to perform a function in support of SR functions were classified as SR and included in the scope of license renewal
 
per 10 CFR 54.4(a)(1). For the exceptions where NSR SSCs are required to remain functional
 
in support of an SR function (and were not classified as SR), the supporting SSCs are included
 
within the scope of license renewal pursuant to 10 CFR 54.4(a)(2).
Overhead-Handling Systems. Overhead-handling systems located in structures that contain SR SSCs were considered in scope if they had the ability to drop a load resulting in damage to an
 
SSC that prevents satisfactory accomplishment of an SR intended function.
Nonsafety-related SSCs Directly Attached to Safety-Related SSCs. The applicant used a spaces approach and included all NSR liquid-filled piping and the corresponding supports that
 
were located in buildings or structures that contain SR equipment within the scope of license
 
renewal in accordance with 10 CFR 54.4(a)(2), with exceptions as discussed below. The
 
applicant used plant drawings, such as flow diagrams, physical drawings, and isometric drawings to determine which systems, or portions of systems, were located in each building or structure. The applicant indicated that, by including within the scope of license renewal all NSR
 
piping and corresponding supports in buildings or structures that contain SR equipment, the
 
need to identify the piping up to the first seismic anchor was eliminated and that at the point
 
where an NSR system leaves the building or st ructure that contains the SR SSCs and enters a building or structure that contains no SR SSCs, the NSR piping and supports are no longer
 
within the scope of license renewal.
2-14 The staff discussed the spaces approach with the applicant and determined that, since all NSR piping and supports in the SR structure were considered within the scope of license renewal in
 
accordance with 10 CFR 54.4(a)(2), the applicant had not identified any "equivalent anchors" as
 
a scoping boundary, but, instead, had marked scoping boundaries at the structure wall. The
 
staff reviewed license renewal boundary drawing 1-47E801, which showed the four main steam
 
lines in red (denoting within scope) in the reactor building. Where the main steam line piping
 
exited the reactor building and entered the turbine building, the color changed from red to black, denoting the change from within scope to outside the scope of license renewal.
The staff's review of LRA Section 2.1 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
In RAI 2.1-2A, dated July 30, 2004, the staff requested the applicant provide the following:
1.A description of the criteria used to determine that the integrity of the in-scope piping functions will be preserved if an age-related degradation failure occurs in the attached
 
NSR piping. 2.A description of how it was determined that the SR piping in the reactor building is adequately supported so that it will remain functional if an age-related degradation
 
occurs in the attached NSR piping in the turbine building. 3.A description of how the methodology ensured that the NSR piping up to first equivalent anchor point was included within the scope of license renewal.
The applicant responded to RAI 2.1-2A(1) and (2) by letters dated September 3, 2004, and October 18, 2004. In those responses, the applicant described the evaluation of SR and NSR
 
portions of the main steam piping system. Specifically, the applicant stated, in part, that the
 
seismic Class I portions of the four main steam lines have anchors isolating them from the
 
seismic Class II piping. The seismic Class I/II interface is at the anchor. The piping up to the
 
anchor is designed to seismic Class I requirements. The anchor locations are inside the reactor
 
building, outboard of the isolation valves. The piping up to the anchor, and the anchor, is
 
included within the scope of license renewal per 10 CFR 54.4(a)(1).
The NSR piping segments extending from the anchors to the reactor building/turbine building interface are qualified to seismic Class II pressure retention requirements to support secondary
 
containment. Since secondary containment is an SR function, these piping segments are in the
 
scope of license renewal and are shown in red on the license renewal drawing. This is
 
consistent with BFN's scoping methodology document which states that some NSR SSCs have
 
been determined to perform SR intended functions (e.g., secondary containment, or main steam
 
alternate leak path). As such, the applicant identified all piping supports, and other components
 
inside secondary containment that are required to maintain the structural integrity of the
 
secondary containment and verified that these SSCs were brought into scope. Additionally, the
 
applicant stated that it would identify any additional piping, supports, and other components
 
outside secondary containment that are required to maintain the structural integrity of the
 
secondary containment prior to the period of extended operation.
After review of the information provided by the applicant regarding its evaluation, the staff held a teleconference with the applicant on May 3, 2005, and informed the applicant that any additional 2-15 SSCs outside secondary containment necessary to maintain the structural integrity of the secondary containment must be identified and evaluated for aging effects as part of the current
 
license renewal activities. As a result, the applicant performed a supplemental review of the
 
SSCs associated with the secondary containment piping to identify those that are necessary to
 
maintain the structural integrity of the secondary containment. This supplemental review was
 
provided to the staff in a letter from the applicant, dated May 31, 2005. Specifically, the
 
applicant described its supplemental review process, which included a review of plant drawings
 
and piping system qualification documentation and performance of plant system walkdowns to identify the NSR piping, supports, and other components that are within the scope of license
 
renewal for 10 CFR 54.4(a)(2) for secondary containment qualification. The results of this
 
supplemental review identified several system boundary changes and identification of several
 
new component types, materials, or environments t hat affected the AMR results. Details of the scoping results that expanded the boundaries of these systems and revisions to the AMR
 
results are discussed in SER Sections 2.3, 2.4, and 3.5, respectively.
Based on the applicant's supplemental evaluation of SSCs associated with the secondary containment, which included a review of plant system drawing, piping and support qualification
 
documentation, and extensive plant system wa lkdowns, the staff determined that the applicant had performed an adequate analysis to identify certain additional piping, components, and
 
structures to be included within the scope of license renewal. The staff concluded that the
 
analysis and inclusion of additional SSC's within the scope of license renewal adequately
 
addressed RAI 2.1-2A(1) and (2). Therefore, the staff's concerns described in the RAI are
 
resolved.By letters dated September 3, 2004, October 18, 2004, January 31, 2005, and February 28, 2005, the applicant addressed RAI 2.1-2A(3) as discussed below.
The applicant indicated that during the restart of Units 2 and 3, and during the current restart process for Unit 1, the seismic Class I qualification documentation had been updated to ensure
 
that the analyzed configuration reflected the as-built configuration. This documentation
 
implements the CLB and provides the information necessary to determine the NSR piping and
 
components that are necessary to maintain qualification of the connected SR piping and
 
components. To ensure the license renewal boundaries are consistent with the CLB
 
requirements, the applicant performed a review of the seismic Class I qualification
 
documentation to identify the NSR piping, supports/equivalent anchors, and other components
 
that are within the scope of license renewal for 10 CFR 54.4(a)(2) for the cases where NSR
 
piping or components are directly connected to SR piping or components.
This review included the verification of each seismic Class I boundary identified in the CLB. The seismic Class I boundaries could typically be included in one of the following categories:
* Base-Mounted Equipment (pump, heat exchanger, tank, etc.) - a rugged component that is designed to provide support for connected piping and impose no loads on the
 
piping. The review assures that when base-mounted equipment implements a seismic
 
Class I boundary, the piping from the boundary to the equipment, and the equipment
 
itself, are included within the scope of license renewal.
* Pipe Anchor - a special pipe support, which resists all six degrees of freedom, that has been designed and installed on the piping. The review assures that when a pipe anchor 2-16 implements a seismic Class I boundary, the piping from the boundary to the pipe anchor, and the pipe anchor itself, are included within the scope of license renewal.
* Embedded Piping Segment - where piping is structurally attached (usually welded) to piping that is embedded in a concrete floor or wall and acts as an anchor. The review
 
assures that when an embedment implements a seismic Class I boundary, the piping
 
from the boundary to the embedment, and the embedment itself, are included within the
 
scope of license renewal.
* Large Run Line - when a branch line moment of inertia is significantly smaller than a run line's moment of inertia, the branch line can be decoupled from the run line. The run line
 
is then considered as an equivalent anchor. The review assures that in a case in which a
 
large run line forms a seismic Class I boundary, the large run line is included within the
 
scope of license renewal.
* Piping Free End - piping qualified up to an end that has no structural connection. The review assures that when a seismic Class I boundary is formed by a piping free end, all
 
of the piping and supports from the boundary to piping free end(s) are included within
 
the scope of license renewal.
* Flexible Connection - where a pipe stress analysis terminates at a flexible connection that is considered as a free end in that analysis. The review assures that when a flexible
 
connection forms a seismic Class I boundary, the piping and supports from the boundary
 
to the flexible connection are included within the scope of license renewal.
* Overlap Regions - where a series of single or multidirectional pipe supports have been installed to isolate one region of piping from another. The review assures that when an
 
overlap region forms a seismic Class I boundary all of the piping and supports in the
 
overlap region are included within the scope of license renewal.
The applicant indicated that the results of the review brought new portions of piping, components of existing systems, and two additional structures within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2).
The staff determined that the applicant had performed an analysis that defined several types of seismic Class I boundaries and had appropriately used this information to identify certain
 
additional piping, components, and structures to be included within the scope of license
 
renewal. The staff concluded that the analysis and inclusion of additional SCs within the scope
 
of license renewal adequately addressed RAI 2.1-2A(3). Therefore, the staff's concern
 
described in RAI 2.1-2A(3) is resolved.
Nonsafety-Related SSCs in Proximity of Safety-Related SSCs. The applicant used a spaces approach and included all NSR liquid-filled piping and the corresponding supports that are
 
located in buildings or structures that contain SR equipment within scope in accordance with
 
10 CFR 54.4(a)(2), with exceptions as discussed below. The applicant used plant drawings, such as flow diagrams, physical drawings, and isometric drawings to determine which systems, or portions of systems, are located in each building or structure.
NSR high-energy piping located in buildings or structures that contain SR equipment was included within the scope of license renewal per 10 CFR 54.4(a)(2). The applicant had taken an
 
exception to this approach by not including within the scope of license renewal the NSR pipe 2-17 located in the SR-classified turbine building, although twelve SR main steam tunnel temperature switches are located in the main steam tunnel portion of the turbine building. In addition to the
 
main steam lines, the main steam tunnel houses other NSR piping and components. The staff
 
was unable to determine if the applicant demonstrated that the twelve temperature switches
 
installed in the steam tunnel portion of the turbine building are adequately protected from
 
age-related degradation of NSR SSCs.
In RAI 2.1-2B, dated July 30, 2004, the staff requested the applicant to address whether the 12 temperature switches installed in the main steam tunnel portion of the turbine building are adequately protected from wetting or spraying from the failure of NSR SSC components due to
 
age-related degradation.
In its responses, by letters dated September 3, 2004, and October 18, 2004, the applicant addressed RAI 2.1-2B.
The applicant indicated that a design change notice (DCN) will be developed that will qualify the circuits for wetting and spray from a moderate/low-energy line break. The DCN will replace the
 
temperature switch connectors and will also seal conduits as required to ensure circuit integrity
 
and to mitigate the consequences of a moderate/low-energy line break. The applicant indicated
 
that identification of moderate/low-energy, liquid-filled piping systems located in the vicinity of the temperature switches was not necessary since the switches will be qualified for the
 
environment that would result from a moderat e/low-energy line break. The applicant indicated that the DCN will be implemented prior to the period of extended operation.
The staff reviewed the response to RAI 2.1-2B and determined that the applicant had indicated that a DCN would be issued to modify the temperature switches located within the main steam
 
tunnel such that they would be qualified to perform in an environment resulting from a moderate/low-energy line break. Therefore, the staff concern described in RAI 2.1-2B is
 
resolved.NSR moderate/low-energy piping located in buildings or structures that contain SR equipment was generally included within the scope of license renewal in accordance with
 
10 CFR 54.4(a)(2). The exceptions to inclusion within scope were identified in the LRA as the
 
turbine building (discussed above), intake pumping station, and the RHRSW tunnel.
In RAI 2.1-2C, dated July 30, 2004, the staff stated that in engineering report "10CFR54.4(a)(2)
Scoping Methodology," the applicant discussed the basis for exclusion of moderate/low energy
 
piping located within the intake pumping station and RHRSW tunnel. The report stated that
 
active SR components located within the intake pumping station were environmentally qualified and were normally exposed to outside weather conditions. In addition, the water from the NSR
 
moderate/low energy pipe in the intake pumping st ation would not adversely affect the passive SR components (pipes or manual valves) since degradation would occur gradually over a period of time and system leakage would be detected prior to such degradation by plant personnel
 
during activities such as operator rounds, routine radiation protection surveys or system
 
engineer walkdowns. The same basis was applied to the potential effect of fluid from NSR SSCs
 
on SR SSCs within the RHRSW tunnel (which only contain passive SR SSCs). Therefore, the
 
staff requested that the applicant provide the additional information concerning the basis for the
 
conclusion that failure of moderate/low energy fluid-filled NSR SSCs in the proximity of passive
 
SR SSCs will not adversely affect the SR SSCs.
2-18 By letters dated September 3, 2004, and October 18, 2004, the applicant addressed RAI 2.1-2C, as discussed below.
The applicant reviewed the NSR fluid piping systems contained in the RHRSW tunnel and determined that all piping systems are within the scope of license renewal, with the exception of
 
the 24-inch raw cooling water discharge piping, which was subsequently included within the
 
scope of license renewal. The applicant indicated that exposure duration was not used in the
 
scoping process.
In addition, the applicant reviewed the effect of water spray from NSR systems at the intake pumping station structure. The applicant determined that the SR equipment located within the
 
intake pumping structure was designed for a normal operating environment of outside air, which
 
includes precipitation and operation in a wetted environment. The applicant revised its scoping
 
methodology to address components located in t he lower compartments of the intake pumping station, which are subject to submergence during the probable maximum flood. The applicant
 
determined that all SR passive electrical components installed at the intake pumping station are
 
located above probable maximum flood level and are designed to either be protected from the
 
effects of a wetted environment or designed to perform their function in a wetted environment.
 
The applicant indicated that exposure duration was not used in the scoping process.
The staff reviewed the response to RAI 2.1-2C and determined that the applicant had not taken credit for exposure duration to exclude any NSR piping located within the RHRSW tunnel from
 
scoping consideration. The applicant had included all applicable NSR piping within the scope of
 
license renewal for the RHRSW tunnel. In addition, the applicant had determined that SR
 
components in the intake pumping station, that are located above the probable maximum flood
 
level are either protected from the effects of a wetted environment or designed to perform their
 
function in a wetted environment. The staff concluded that this adequately resolved RAI 2.1-2C.
Conclusion. On the basis of the additional information supplied by the applicant, including determining that certain additional SSCs that would be placed within the scope of license
 
renewal based on analysis and additional review, determining that certain SSCs were qualified
 
for the environment, identifying the basis for the definition and use of the first equivalent anchor, and reviewing the results of NRC inspection and audit activities, the staff concluded that the
 
applicant had supplied sufficient information to demonstrate that all SSCs that meet the
 
10 CFR 54.4(a)(2) scoping requirements have been identified as being within the scope of
 
license renewal.
Application of the Scoping Criteria in 10 CFR 54.4(a)(3). Section 54(a)(3) of 10 CFR requires, in part, that the applicant consider all SSCs relied on in safety analyses or plant evaluations to
 
perform a function that demonstrates compliance with NRC regulations for fire protection
 
(10 CFR 50.48), EQ (10 CFR 50.49), ATWS (10 CFR 50.62), and SBO (10 CFR 50.63) to be
 
within the scope of license renewal.
The applicant performed the initial scoping for regulated events by evaluating CLB information relevant to each regulated event to identify if the structure or system met the scoping criteria of
 
10 CFR 54.4(a)(3). For these events, the applicant developed an engineering report describing
 
the relevant Rule requirements. A functional description of the implementation includes the
 
process to identify the scoping boundaries associated with the systems credited, the intended
 
functions applicable to the requirement, information on how to record the results of the 2-19 evaluation in the license renewal database and appropriate MEL, a list of CLB information sources used for the analysis, and a list of systems and components determined to be within
 
scope for the given regulated event.
* Fire Protection. The applicant provided a description of the scoping of SSCs required to demonstrate compliance with the fire protection requirements in 10 CFR 50.48. The
 
applicant stated that the fire protection report, EMPAC, and the CLB had been reviewed
 
to ensure that SSCs required to perform the necessary safe shutdown functions and to
 
minimize the risk of radioactive releases to the environment during and following fires
 
are included within the scope of license renewal. In addition, the applicant stated that it
 
considered the NRC's Interim Staff Guidance (ISG) related to scoping fire protection
 
equipment, ISG-07, to determine if a syst em performs a function that demonstrates compliance with NRC's regulations. Specifically, the applicant verified that the EMPAC
 
contains a designated field identifying components that are part of the fire protection
 
program consistent with the CLB. The staff reviewed the process used by the applicant
 
to identify those components and verified, through review of a selection of scoping
 
results, that the EMPAC information was adequately incorporated into the license
 
renewal evaluation.
* Environmental Qualification. The applicant stated that BFN maintains documents containing detailed information related to environmental qualification of components at
 
BFN. Additionally, EMPAC provides a list of components that are subject to an EQ
 
program. The applicant reviewed these documents to prepare the list of in-scope items
 
for the LRA. Specifically, EMPAC contains a designated field identifying components
 
that are part of the EQ program. The staff reviewed the process used by the applicant to
 
identify those components and verified, through review of a selection of scoping results, that EMPAC information was adequately incorporated into the license renewal
 
evaluation.
* Anticipated Transient Without Scram. The applicant reviewed UFSAR Section 7.19 and used the quality-related classification field in EMPAC to identify components of the
 
ATWS mitigation system required by 10 CFR 50.62. EMPAC is a controlled plant
 
component database containing integrated design and maintenance record
 
management information. The plant component database lists plant components at the
 
level of detail for which discrete maintenance or modification activities are typically
 
performed. Specifically, EMPAC contains a designated field identifying components that
 
are credited for ATWS mitigation. The staff reviewed the process used by the applicant
 
to identify those components and verified, through review of a selection of scoping
 
results, that the EMPAC information had been adequately incorporated into the license
 
renewal evaluation.
* Station Blackout. In an NRC letter dated April 1, 2002, the staff provided guidance on the scoping of equipment relied on to meet the requirements of the SBO rule, 10 CFR 50.63.
 
In this letter, the staff noted that, consistent with the requirements specified in
 
10 CFR 54.4(a)(3) and 10 CFR 50.63(a)(1), the plant system portion of the offsite power
 
system that is used to connect the plant to the offsite power source should be included
 
within the scope of the Rule.
In LRA Section 2.1.8.2, the applicant stated that, based on the guidance in the April 1, 2002, letter for SBO recovery, an evaluation was performed to determine, and bring into the scope of 2-20 license renewal, components credited for recovery of the offsite power system. For each of thesystems credited for SBO recovery, the applicant used, as a minimum, information from the SBO calculations and Emergency Operating Procedures and Technical Specification
 
Bases 3.8.1, to determine the appropriate NSR portions of the in-plant electrical system that
 
would be used to connect the offsite power system to the SR portions of the plant electrical
 
system. The applicant performed calculations to summarize the results of a detailed review of
 
SBO CLB documentation. The calculations provided lists of systems with their credited functions and a listing of major components. The applicant did not use the spaces approach to evaluate
 
all plant electrical and I&C components in the SBO offsite power restoration flow path. The
 
applicant provided license renewal drawings that identified the additional components in the
 
offsite power restoration flow paths from 500 kilovolt (kV) and 161 kV switchyards to the plant
 
SR shutdown buses using plant procedures for the restoration of offsite power.
Additionally, an AMR was performed for all long-lived passive structures and components within these systems. A scoping effort identified structures and components of the offsite power
 
system for each plant required to restore power from the onsite switchyard down to the SR
 
busses in the plant. The applicant also stated that the plant offsite power system and these
 
structures and components were classified as satisfying10 CFR 54.4(a)(3) criteria and were
 
included within the scope of license renewal. The staff determined that the applicant's approach
 
to scoping SSCs relied on to demonstrate compliance with the SBO rule (10 CFR 50.63) was
 
consistent with the staff's April 1, 2002, interim guidance.
Conclusion. The staff reviewed a sample of the license renewal database 10 CFR 54.4(a)(3) scoping results and discussed the methodology and results with the applicant's license renewal
 
project personnel. The staff verified that the applicant had identified and used pertinent
 
engineering and licensing information to identify SSCs to be within the required scope in
 
accordance with the 10 CFR 54.4(a)(3) criteria. On the basis of this sample review, discussions
 
with the applicant, and review of the applicant's scoping process, the staff determined that the
 
applicant's methodology for identifying systems and structures meeting the scoping criteria of
 
10 CFR 54.4(a)(3) was adequate.
2.1.3.1.3  System Level Scoping of Structures and Components
 
The applicant started the system-level scoping of structures and components with the review of the SSA calculation, UFSAR descriptions, Maintenance Rule documents, CLB, and
 
design-basis documents to determine the system safety classification level functions and to
 
identify the system intended functions. The SSA provided the system designation and the
 
system function. The relevant flow drawings we re retrieved for the system and description, and their safety classifications were determined. The components were identified and their functions
 
were mapped. The applicant consulted the UFSAR to see if any additional functions were listed
 
therein, because the applicant created the SSA during the restart of Units 2 and 3, listing all the
 
possible system functions.
At the system level, the scoping methodology us ed for electrical and I&C systems was identical to the mechanical system-level scoping. The SSA calculation, UFSAR descriptions, Maintenance Rule documents, and other design-basis documents were reviewed to determine
 
an electrical system's safety classification and to identify the electrical system's intended functions. System-level functions were evaluated against the criteria of 10 CFR 54.4(a). This
 
information was included in the license renewal database for inclusion in the LRA.
2-21 The applicant entered the information on the "System Scoping Results" data sheet for the specific system. The staff reviewed the scopi ng results for the RHR system and observed that the data sheet contained detailed information that identified each component and its parent
 
system, component type, the scoping criteria that it was required to meet, and its associated AMR information.
2.1.3.1.4  Component Level Scoping
 
The applicant reviewed license renewal boundary drawings in conjunction with physical layout drawings and component listings from EMPAC to determine the components within the scope of
 
license renewal. Any component that was needed to fulfill any system intended function or
 
determined to be an NSR component that could prevent satisfactory accomplishment of an SR
 
function was considered to be within the scope of license renewal. The applicant evaluated the
 
components either individually or in groups of like components and functions to ensure that all
 
components were properly addressed. Electrical and I&C components of in-scope mechanical
 
systems were classified as electrical and I&C commodities. Structural components of in-scope mechanical systems were classified as structural commodities. Structural commodities, such as
 
cable trays and their supports, were classified as plant civil system commodities. Pressure boundary components of electrical penetrations were classified as civil commodities. Structural
 
components of in-scope structures that are required to support the intended functions were
 
generally evaluated as generic structural commodities, and not individual components.
Mechanical Component Scoping. The staff reviewed 0-TI-455, "Mechanical Technical Evaluation for License Renewal," Revision 2, dated May 28, 2004. The applicant provided a
 
technical description and overview of the process in Section 4.1, Mechanical Scoping and
 
Screening, of 0-TI-455. Specifically, the applicant stated that systems and components are determined to be within the scope of license renew al if they have been evaluated to meet any of the scoping criteria.
The staff verified that mechanical system evaluation boundaries were established for each system within the scope of license renewal. These boundaries were determined by mapping the
 
pressure boundary associated with system-level license renewal intended functions onto the
 
system flow and control drawings. Mechanical component types were loaded into a scoping and
 
screening database and further review was performed to ensure that all component types were
 
identified. A preparer and an independent reviewer performed a comprehensive evaluation of
 
the boundary drawings to ensure the completeness and accuracy of the review results.
 
Following identification of all system com ponent types, the applicant used the license renewal boundary as an aid to evaluate each component against the scoping criteria of 10 CFR 54.4(a).
 
System components meeting the criteria of 10 CFR 54.4(a) were classified as within the scope
 
of license renewal.
The staff conducted detailed discussions with the applicant's license renewal project personnel and reviewed documentation pertinent to the scoping process. The staff assessed whether the
 
applicant had appropriately applied the scoping methodology outlined in the LRA and
 
implementation procedures and whether the scoping results were consistent with CLB
 
requirements.
The staff reviewed the process of scoping for the RHRSW and ECCW systems. The staff verified that the applicant had identified and highlighted system flow and control drawings to 2-22 develop the system boundaries in accordance with the procedural guidance. The applicant was knowledgeable concerning the process and conventions for establishing boundaries as defined
 
in the license renewal implementation procedures. Additionally, the staff verified that the
 
applicant had independently verified the results in accordance with the governing procedures.
 
Specifically, other personnel knowledgeable of the system had independently reviewed the marked-up drawings to ensure accurate identification of system intended functions. The staff
 
performed additional cross-discipline verification and independent reviews of the resultant
 
highlighted drawings before final approval of the scoping effort.
Conclusion. The staff determined that the applicant's methodology was consistent with the description provided in LRA Section 2.1.4 and that the guidance contained in SRP-LR
 
Section 2.1 was adequately implemented. On the basis of the applicant's detailed scoping
 
implementation procedures and a sampling review of mechanical components scoping results, the staff concluded that the applicant's methodology for identifying mechanical components
 
within the scope of license renewal met the requirements of 10 CFR 54.4(a).
Structural Component Scoping. The applicant performed its structural scoping in accordance with the detailed methodology defined in 0-TI-457, "Civil Technical Evaluations for License
 
Renewal," Revision 2. The scoping procedure was used to evaluate SSCs to identify their
 
functions and determine which are intended functions required for compliance with one or more
 
criteria of 10 CFR 54.4(a)(1)-(3). Initial identification of BFN structures was accomplished by
 
reviewing BFN drawing 0-10E21-series and/or Maintenance Rule documentation, 0-TI-346. For
 
each structure, the applicant further reviewed the drawings and plant databases to identify
 
specific structural components and features. The structural component intended functions for
 
SCs within the scope of license renewal were identified based on the guidance provided in
 
Regulatory Guide (RG) 1.188, "Standard Format and Content for Applications to Renew Nuclear
 
Power Plant Operating Licenses," NEI 95-10, and the SRP-LR. The procedure also described
 
the source design documentation to be used for the evaluation of structures meeting the
 
10 CFR 54.4(a) criteria including the UFSAR, general design criteria (GDC) document, and
 
other appropriate documents. For civil structures, the evaluation boundaries were determined by
 
developing a complete description of each structure with respect to the intended functions
 
performed by the structure and its components. A license renewal database was created for use
 
in compiling the structural scoping results. The database contained (1) a unique identification
 
number for each structure, (2) a list of struct ural components or commodity types associated with the structure, (3) evaluation results for each of the 10 CFR 54.4(a)(1)-(3) criteria for the
 
structure, (4) a description of structural intended functions and source reference information for
 
the functions, and (5) a reference to pertinent license renewal drawings associated with each
 
structure.
License renewal procedure 0-TI-457 was also used to define the evaluation boundaries and discipline interfaces for civil/mechanical and civil/electrical systems. With respect to the
 
civil/mechanical interface, the procedure identified the following component types within
 
mechanical systems that were evaluated as part of the civil review. These component types included: (1) piping system supports, (2) HVAC duct supports, (3) equipment supports and
 
foundations, (4) bolting and fasteners for structural supports and mechanical fasteners that are
 
required for mechanical closure of mechanical components, and (5) whip restraints and jet
 
impingement shields.
2-23 With respect to the civil/electrical interface, the procedure identified the following component types within electrical systems that were ev aluated as part of the civil review. These component types included: (1) cable trays and supports, (2) conduits and supports, (3) electrical cabinets, panels, racks, and other enclosures providing structural integrity, (4) instrument racks, panels, frames, and enclosures providing structural integrity, and (5) electrical and I&C penetrations
 
providing structural support functions.
The staff conducted detailed discussions with the applicant's license renewal project personnel and reviewed documentation pertinent to the scoping process. The staff assessed whether the
 
scoping methodology outlined in the LRA and implementation procedures were appropriately
 
implemented and whether the scoping results were consistent with CLB requirements. The staff
 
also reviewed several plant structural evaluation results for the reactor building and turbine
 
building to verify proper implementation of the scoping process for structural components. The
 
staff also compared a sample of structural components identified in the drawings to the
 
structural list in the license renewal data base to ensure consistency. Based on these audit
 
activities, the staff did not identify any discrepancies between the methodology documented and
 
the implementation results.
Conclusion. The staff determined that the applicant's methodology for structural scoping was consistent with the description provided in LRA Section 2.1.4.3 and the guidance contained in
 
the SRP-LR Section 2.1. Based on a review of information contained in the LRA, the applicant's
 
detailed scoping implementation procedures, and a sampling review of structural component
 
scoping results, the staff concluded that the applicant's methodology for identification of
 
structural components within the scope of license renewal met the requirements of
 
10 CFR 54.4(a).
Electrical and I&C Scoping. The staff reviewed 0-TI-456, "Electrical Technical Evaluations For License Renewal," which describes the electrical and I&C scoping and screening process and
 
discussed the methodology and results with the applicant's cognizant engineers. With the
 
exception of components in the SBO offsite power restoration flow path, plant electrical and I&C components were evaluated using a "spaces" approach. The spaces approach identifies the
 
electrical and I&C commodity groups that are installed in the plant and the limiting
 
environmental conditions for each group. The spaces approach then determines if any area
 
environment is more severe than the limiting environment for the commodity group. If the area environment is more severe than a commodi ty group's limit, and if a component in the commodity group is actually located in the ar ea, an AMR is required for that commodity group.
For this LRA, the applicant used a bounding spaces approach, as described in NEI 95-10.
Electrical and I&C component types used plant-wide were identified without regard to the plant
 
system they are in. The applicant used the lis ting provided by NEI 95-10, Appendix B as the basis for this list. Electrical component types were identified from the plant controlled computer
 
database, EMPAC. Then these component types were assembled into commodity groups such
 
as breakers, switches, and cables using the NEI 95-10, Appendix B list as a starting point. The
 
EMPAC database has a fine division of component titles based on component performance
 
characteristics, so sub-commodity groups were formed to separate components into specific groups with common applications or materials. Thus under the commodity group, "circuit breakers," there may be a number of sub-commodity groups including all the circuit breakers
 
identified in EMPAC as having common application, operating characteristics, fabrication 2-24 materials, etc. The result is a detailed list by commodity and sub-commodity of all electrical and I&C components installed in the plant.
An exception to the spaces approach was the identification of electrical and I&C equipment needed for the SBO event offsite power restoration. Using the intended-function approach, the applicant developed license renewal drawings showing the basic electrical distribution paths for
 
SBO offsite power restoration. Plant operating procedures were used to develop these SBO
 
offsite power restoration license renewal drawings and to identify the components required to
 
perform the function. The staff determined that the scoping and screening methodology used in
 
0-TI-456, "Electrical Technical Evaluations For License Renewal"; and described by the
 
applicant's engineers during the audit provided adequate guidance, was consistent with the
 
requirements of 10 CFR 54.4 for the scoping evaluation of electrical components.
Conclusion. The staff determined that the applicant's methodology for electrical and I&C scoping was consistent with the description provided in LRA Section 2.1.4.2 and the guidance
 
contained in the SRP-LR. Based on review of information contained in the LRA, the applicant's
 
detailed scoping implementation procedures, and a sampling review of electrical component
 
scoping results, the staff concluded that the applicant's methodology for identification of
 
electrical and I&C components within the scope of license renewal met the requirements of
 
10 CFR 54.4(a).2.1.3.2  Screening Methodology The staff reviewed the screening methodology used by the applicant to determine if mechanical, structural, and electrical components within the scope of license renewal would be subject to
 
further aging management evaluation. The applicant described the screening methodology in
 
LRA Section 2.1.5. In general, the applicant's screening approach consisted of evaluations to
 
determine which structures and components within the scope of LRA were passive and
 
long-lived. Passive and long-lived structures and components were then subject to an AMR.
The staff evaluated the applicant's screening methodology against criteria contained in 10 CFR 54.21(a)(1) and 10 CFR 54.21(a)(2) using the review guidance contained in SRP-LR
 
Section 2.1.3.2, "Screening." The staff evaluation of the applicant's screening approach for each
 
of these disciplines is discussed below.
2.1.3.2.1  Mechanical Component Screening
 
The staff reviewed the methodology used by the applicant to determine if mechanical components within the scope of license renewal would be subject to further AMR. For
 
mechanical components, the applicant applied a screening process to each mechanical system
 
determined to be within the scope of license renewal in order to determine the types of
 
mechanical component commodities within the systems and the various materials and
 
environments to be considered in the AMR. The applicant then established evaluation
 
boundaries for the various plant mechanical systems in order to further identify individual
 
mechanical components for review.
The listing of mechanical components was facilitated by combining these items into commodity groups from a review of each boundary drawing. The applicant placed these commodity groups
 
into the license renewal database and evaluated them in accordance with the screening criteria 2-25 described in 0-TI-455. The applicant provided the staff with a detailed discussion of the process and provided screening report information from the license renewal database that described the
 
screening methodology, as well as a sample of the screening results reports for a selected
 
group of SR and NSR systems. The staff determined that the screening methodology was
 
consistent with the requirements of the Rule and that implementation of the methodology will
 
identify SCs that meet the screening criteria of 10 CFR 54.21(a)(1).
During the audit, the staff reviewed the methodology used by the applicant to identify and list the mechanical components and commodities subject to an AMR, as well as the applicant's
 
technical justification for this methodology. The staff discussed the methodology and results
 
with the applicant's cognizant engineers and senior staff. The staff also examined the
 
applicant's results from the implementation of th is methodology by reviewing a sample of the mechanical systems identified as within t he scope of license renewal. These systems included the RHRSW system and EECW system. The re view included the evaluation boundaries and resultant in-scope components, the corresponding component-level intended functions, and the
 
resulting list of mechanical components and commodity groups subject to an AMR.
The staff reviewed several summary screening reports, which list a breakdown of the mechanical components that are within the scope of license renewal. Each report lists several
 
categories, including component type, component material, whether an AMR is required, and an
 
extensive comment section. The staff also reviewed a sample of the mechanical drawing
 
packages assembled by the applicant and discussed the process and results with the cognizant
 
engineers who performed the review. The staff did not identify any discrepancies between the
 
methodology documented and the implementation results.
Conclusion. The staff determined that the applicant's mechanical component screening methodology was consistent with the guidance contained in the SRP-LR and was capable of
 
identifying those passive, long-lived components within the scope of license renewal that are
 
subject to an AMR.
2.1.3.2.2  Structural Component Screening
 
The staff reviewed 0-TI-457, "Civil Technical Evaluations For License Renewal," which outlined the applicant's methodology to determine if SCs within the scope of license renewal would be
 
subject to an AMR. The screening process applied to in-scope buildings and civil structures was
 
designed to determine the structural elements and construction materials, as well as to
 
determine the environments to which these buildi ngs and civil structures will be exposed so that these factors could be considered in the AMR. Engineering document 0-TI-457 Section 6.3, "Structures Screening," describes the guidance for the structural screening process. For all
 
structural component types with intended functions, the applicant then determines if the
 
component type is long-lived. The applicant us ed existing plant program procedures and operating experience to determine if the component type was subject to replacement based on
 
a qualified life or whether it was long-lived.
During the audit of the applicant's license renewal scoping and screening process, the staff reviewed the methodology used by the applicant to identify and list the structural components
 
and structural commodities subject to an AMR as well as the applicant's technical justification
 
for this methodology. The staff discussed the methodology and results with the applicant's
 
cognizant engineers and senior staff. The applicant provided the staff with a detailed discussion 2-26 of the process and provided technical reports that described the screening methodology as well as a sample of the screening results for a selected group of structures.
The staff also examined the applicant's results fr om the implementation of this methodology by reviewing a sample of the reactor building and turbine building plant structures identified as
 
being within the scope of license renewal. The review included the evaluation boundaries and
 
resultant in-scope components, the corresponding component-level intended functions, and the
 
resulting list of structural components and structural commodity groups subject to an AMR.
Conclusion. The staff determined that the applicant's structural component screening methodology was consistent with the guidance contained in the SRP-LR and was capable of
 
identifying those passive and long-lived components within the scope of license renewal that
 
are subject to an AMR.
2.1.3.2.3  Electrical Component Screening.
 
The staff reviewed the applicant's procedure 0-TI-456, "Electrical Technical Evaluations For License Renewal," which provided guidance on the screening of electrical and I&C components.
 
The applicant used a bounding spaces approach as described in NEI 95-10, Revision 3, to
 
perform the electrical evaluation. The electrical and I&C component types were identified from
 
EMPAC. These component types were assembled into commodity groups such as breakers, switches, and cables using the NEI 95-10, Appendix B, list and supplemented with site-specific
 
information. The applicant then applied the screening criteria to determine those electrical
 
commodities subject to an AMR.
The staff discussed the methodology and results with the applicant's cognizant engineers and senior staff. The staff also examined the applicant
's results from the implementation of this methodology by reviewing several electrical and I&C commodity reports and samples from the license renewal database. The review verified that the applicant's staff had consistently applied
 
the screening criteria to identify those electrical and I&C commodity groups subject to an AMR.
 
The staff determined that the electrical screening process was consistent with criteria in
 
10 CFR 54.21(a)(1)(ii) and excluded those components or commodity groups that are subject to
 
equipment qualification requirements. The staff did not identify any discrepancies between the
 
methodology documented and the implementation results.
The staff also reviewed the applicant's approach to scoping and screening of electrical fuse holders. In license renewal ISG-5, "Identification and Treatment of Electrical Fuse Holders for
 
License Renewal," dated March 10, 2003, the staff stated that, consistent with the requirements
 
specified in 10 CFR 54.4(a), fuse holders (including fuse clips and fuse blocks) are considered
 
to be passive electrical components. Fuse holders would be scoped, screened, and included in
 
the AMR in the same manner as terminal blocks and other types of electrical connections that
 
are currently being treated in the process. This staff position applies only to fuse holders that
 
are not part of a larger assembly, but support SR and NSR functions in which the failure of a
 
fuse precludes a safety function from being accomplished (10 CFR Part 54.4(a)(1) and
 
10 CFR 54.4(a)(2)). As described in LRA Sections 2.1.8.5, and 3.6.2.3.1, the applicant
 
developed a process for identifying and evaluating fuse holders as part of its license renewal
 
evaluation. The process included using EMPAC to identify fuses in the plant and then to apply a
 
series of evaluations and screening to identify a subset of the plant fuses which would
 
potentially be susceptible to various effects of moisture or chemical contamination, thermal 2-27 cycling, vibration, and mechanical stress. The applicant evaluated plant operating experience and determined that fatigue due to mechanical stress was an applicable aging
 
effect/mechanism. The applicant then evaluated all remaining fuses to determine if any were
 
susceptible to mechanical stress. The staff reviewed the applicant's process for identifying and
 
evaluating the fuse holders and determined it was adequate.
Conclusion. The staff determined that the applicant's electrical and I&C screening methodology was consistent with the guidance contained in the SRP-LR and was capable of identifying
 
passive, long-lived components within the scope of license renewal that are subject to an AMR.
 
====2.1.4 Conclusion====
The staff's review of the information presented in LRA Section 2.1, the supporting information in the scoping and screening implementation procedures and reports, the information presented
 
during the scoping and screening methodology audit, and the applicant's responses to the
 
staff's RAIs formed the basis of the staff's safety determination. The staff verified that the
 
applicant's scoping and screening methodology was consistent with the requirements of the
 
Rule and the staff's position on the treatment of NSR SSCs.
On the basis of this review, the staff concluded that there is reasonable assurance that the applicant's methodology for identifying the SSCs within the scope of license renewal and the
 
structures and components requiring an AMR is consistent with the requirements of
 
10 CFR 54.4 and 10 CFR 54.21(a)(1).
2-28 2.2  Plant-Level Scoping Results
 
====2.2.1 Introduction====
In LRA Section 2.1, the applicant described the methodology for identifying the systems and structures (SSs) within the scope of license renewal. In LRA Section 2.2, the applicant used the
 
scoping methodology to determine which of the SSs are required to be included within the scope of license renewal. The staff reviewed the plant-level SSs relied upon to mitigate DBEs, as required by 10 CFR 54.4(a)(1), or whose fa ilure could prevent satisfactory accomplishment of any of the SR functions, as required by 10 CFR 54.4(a)(2), as well as the SSs relied on in
 
safety analyses or plant evaluations to perform a function that is required by any of the regulations referenced in 10 CFR 54.4(a)(3).2.2.2  Summary of Technical Information in the Application In LRA Tables 2.2.1 and 2.2.2, the applicant provided a list of the plant systems and structures, respectively, identifying those that are within the scope of license renewal and those that are not
 
within the scope of license renewal. Based on the DBEs considered in the plant's CLB, other
 
CLB information relating to NSR systems and structures, and certain regulated events, the
 
applicant identified those plant-level systems and structures that are within the scope of license
 
renewal, as defined by 10 CFR 54.4.
 
====2.2.3 Staff====
Evaluation In LRA Section 2.1, the applicant described its methodology for identifying the systems and structures that are within the scope of license renewal and subject to an AMR. The staff
 
reviewed the scoping and screening methodology and provided its evaluation in the safety
 
evaluation report (SER) Section 2.1. To verify that the applicant properly implemented its methodology, the staff focused its review on the implementation results, as shown in LRA
 
Tables 2.2.1 and 2.2.2, and added systems due to the changed scoping methodologies to
 
confirm that there were no omissions of plant-level systems and structures within the scope of
 
license renewal.
In response to RAI 2.1-2A(3), described in SER Section 2.1, the applicant revised the methodology used to determine the NSR SSCs to be included in the scope of license renewal in
 
accordance with the requirements of 10 CFR 54.4(a)(2). The applicant's response to
 
RAI 2.1-2A(3) and supplemental information related to implementation of the revised scoping
 
methodology are documented in the applicant's response, dated February 28, 2005. As a result
 
of the implementation of the scoping methodology changes, the applicant expanded the scope
 
of license renewal and added the following mechanical systems that had additional in-scope
 
piping or components:
* condensate and demineralized water system
* containment system
* reactor building closed cooling water system
* auxiliary decay heat removal system
* fuel pool cooling and cleanup system
* CO 2 system
* sampling and water quality system 2-29
* off-gas system
* radioactive waste treatment system
* diesel generator starting air system The applicant also added the following structures to the scope of license renewal:
* radwaste building
* service building In response to a follow-up question of RAI 2.1-2A(1), dated May 31, 2005, described in SER Section 2.1, the applicant provided supplemental information on the implementation of the
 
revised scoping methodology of NSR piping segments that support secondary containment
 
penetrations qualified to seismic Class II pressure retention requirements.
As a result of the implementation of the scoping methodology changes, the applicant added the following mechanical systems that had additional piping or components added to the scope of
 
license renewal:
The following mechanical systems only had systems boundary changes. No new component types, materials, or environments that affect ed either the scoping/screening or AMR results in the LRA were added.
* main steam system
* auxiliary boiler system
* raw cooling water system
* station drainage system
* high pressure coolant injection system
* residual heat removal system
* radioactive waste system
* fuel pool cooling and cleanup system
* radiation monitoring system The following mechanical systems had systems boundary changes. For some of these systems, new component types were added that affected the scoping/screening results in the
 
LRA. For all systems listed, new components, ma terials or environments that affected the AMR results in the LRA were added.
* condensate and demineralized water system
* feedwater system
* potable water system
* service air
* containment system The remainder of the mechanical systems were not affected by this review.
 
The staff reviewed the selected systems and structures that the applicant had not identified as falling within the scope of license renewal to ve rify whether the systems and structures have any intended functions that would require their inclusion within the scope of license renewal in
 
accordance with 10 CFR 54.4. The staff's review of the applicant's implementation was 2-30 conducted in accordance with the guidance described in SRP-LR Section 2.2, "Plant-Level Scoping Results."
The staff sampled the contents of the UFSAR based on the systems and structures listed in LRA Tables 2.2.1 and 2.2.2 to determine whether there are any systems or structures that may
 
have intended functions within the scope of license renewal, as defined by 10 CFR 54.4, but
 
were omitted from within the scope of license renewal. The staff did not identify any omissions.
 
====2.2.4 Conclusion====
The staff reviewed LRA Section 2.2 and the supporting information in the UFSAR to determine whether any systems and structures within t he scope of license renewal had not been identified by the applicant. The staff's review did not identify any omissions. On the basis of this review, the staff concluded that the applicant had properly identified the systems and structures that are
 
within the scope of license renewal in accordance with 10 CFR 54.4.
2-31 2.3  Scoping and Screening Results: Mechanical Systems This section documents the staff's review of the applicant's scoping and screening results for mechanical systems. Specifically, this sect ion discusses the following mechanical systems:
* reactor coolant systems
* engineered safety features
* auxiliary systems
* steam and power conversion systems In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and list passive, long-lived structural SSCs that are within the scope of license renewal and subject to
 
an AMR. To verify whether the applicant has properly implemented its methodology, the staff focused its review on the implementation results. This approach allowed the staff to confirm that
 
there were no omissions of mechanical system components that meet the scoping criteria and are subject to an AMR.
In the LRA, the applicant described a methodology for mechanical systems scoping and screening that interprets 10 CFR 54.21(a) differently from previous LRAs and the SRP-LR.
 
Specifically, the applicant did not define component-level scoping boundary. The applicant
 
combined passive, long-lived, and intended function criteria into one screening process to meet
 
the requirements of 10 CFR 54.21(a)(1). The applicant highlighted those components on the
 
license renewal drawings that are passive, long-lived, and have intended functions as being
 
subject to an AMR. Therefore, some of the components that have intended functions may not
 
be identified and listed in the LRA Section 2.3 tables or highlighted on the license renewal
 
drawings, because the component scoping boundary is not defined.
The methodology used by previous LRA applicants, consistent with the SRP-LR review guidance, describes two steps to perform scoping and screening. The first step, scoping, identifies those SSCs within the scope of license renewal in accordance with 10 CFR 54.4(a).
 
The applicant then identified the components of the in-scope system that have intended
 
functions to be included in the license renewal scope in accordance with the criteria of
 
10 CFR 54.4(a). The component scoping boundary within a system is then highlighted on
 
license renewal drawings. The second step, screening, identifies those components in the
 
scoping boundary that are passive and long-lived in accordance with 10 CFR 54.21(a)(1). The
 
resulting components from these scoping and screening steps are subject to an AMR. This
 
matter was further complicated because the drawings for Unit 1 only highlighted those portions
 
of the system that are subject to an AMR and are not expected to change as a result of
 
modifications needed to bring the CLB for Unit 1 in line with Units 2 and 3.
Because the applicant used a different scoping and screening process and provided insufficient information in its LRA associated with this methodology, the staff was unable to determine
 
whether there were any omissions of co mponents from the scope of license renewal and subject to an AMR. The applicant did not provide scoping information at the component level
 
equivalent to that provided by previous LRA applicants for the review of systems in LRA Section 2.3.
To better understand the applicant's scoping methodology, the staff conducted an audit review at the TVA offices in Chattanooga, TN, between June 7 and 10, 2004, to review the applicant's 2-32 license renewal project guidelines and procedures. The purpose of this plant audit was to determine, by review of plant information, t hat system components within the scope of license renewal are identified and that the components of the in-scope systems subject to an AMR are screened. The staff reviewed the applicant's site documentation in the following areas:
* department procedure for license renewal technical evaluations
* mechanical technical evaluations for license renewal
* SBO calculations
* system reports To ensure that all components of an in-scope system were screened, or identified as passive and long-lived in accordance with 10 CFR 54.21(a)(1), the staff audited the system report for the
 
main steam system. Additionally, the staff revi ewed the SBO calculations to determine if any systems were omitted from scope in accordance with 10 CFR 54.4(a)(3). In its trip report, the
 
staff documented which procedures and reports were reviewed at the plant site.
As a result of the staff's review of LRA Section 2.3, the staff found that additional clarification was needed to determine whether the applicant's mechanical component-level scoping for the
 
in-scope systems was adequate. Therefore, by letter dated August 31, 2004, the staff issued
 
RAIs to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a). The following paragraphs describe the staff's RAIs and the applicant's
 
responses.
In RAI 2.3-1, the staff stated that many of the tables in LRA Section 2.3 list "fittings" as a component type subject to an AMR. The term "fi ttings" typically refers to components such as elbows, tees, unions, reducers, caps, flanges, etc., which are an integral part of piping systems.
 
LRA Section 2.3.5 lists other components that fall under the component type "fittings" but does
 
not list the above components. Therefore, the staff requested the applicant to confirm that
 
components such as those listed above are considered as part of the component type "fittings"
 
in the LRA tables, or to state if they are considered as part of another listed component type.
In its response, by letter October 19, 2004, the applicant stated that elbows, tees, unions, reducers, caps, flanges, etc., are not typically shown with UNIDs on the license renewal
 
drawings, and that they were not listed in LRA Section 2.3.5. LRA Section 2.3.5 was generated
 
to help identify components that are shown on boundary drawings, have a specific UNID, and
 
are included in a commodity. The applicant further stated that components such as elbows, tees, unions, reducers, caps, flanges, quick disconnects, thermal sleeves, aux heads, and
 
drains are included in commodity type "fittings."
Based on its review, the staff found the applicant's response to RAI 2.3.-1 acceptable. It confirms that the components addressed in the RAI are already included in the component type "fittings" as being subject to an AMR. Therefore, the staff's concern described in RAI 2.3-1 is
 
resolved.In RAI 2.3-2, the staff stated that LRA Section 2.1.7.9, Group (c) states that "oil, grease, and component filters" are short-lived and are periodica lly replaced. It further states that various plant procedures are used in the replacement of oil, grease, and component filters that are
 
within the scope of license renewal. In the process of verifying the results of the above
 
applicant's methodology, the staff raised the following questions.
2-33 Because the LRA uses AMR boundary drawings instead of scoping boundary drawings, the components that are within the scope of license renewal but not subject to an AMR are not
 
highlighted on the drawings. Therefore, the staff was unable to determine, for mechanical
 
systems, whether all in-scope oil, grease, and component filters had been identified in
 
accordance with 10 CFR 54.4. Additionally, the staff could not determine whether plant
 
procedures exist and are adequate for the all in-scope "oil, grease, and component filters" that
 
are not subject to an AMR. For example, "cr ane system" is within the scope of license renewal in accordance with 10 CFR 54.21(a)(2); however, filters of the system are not listed in LRA
 
Table 2.3.3.34 as component types subject to an AMR. Additionally, no drawings were provided for this system. The staff could not determine w hether this system contains any in-scope oil, grease, and component filters, or whether the plant procedures are adequate for them.
 
Therefore, in RAI 2.3-2, the staff requested the applicant to do the following:  1.Verify all the in-scope oil, grease, and component filters that are identified in the license renewal boundary drawings. If not, list those in-scope oil, grease, and component filters
 
that are not identified in the drawings. 2.Identify the plant procedures that are used for the replacement of every in-scope oil, grease, and filter that is not subject to an AMR to demonstrate that the oil, grease, or
 
filter is replaced on a periodic basis and identify the specific period. 3.Identify those in-scope oil, grease, and component filters without proper plant procedures that are subject to an AMR.
In its response, by letter October 19, 2004, the applicant stated:  1.The boundary drawings were not intended to depict oil or grease. All filters associated with mechanical systems are not depicted on boundary drawings. The
 
boundary drawings are based on flow diagrams which depict components in the
 
system fluid flow path (i.e., pressure boundary). Even though most discrete
 
components are shown on the flow diagram s, the flow diagrams show various levels of detail associated with vendor supplied skids. For example, some flow
 
diagrams associated with vendor supplied skids show the associated lubricating
 
oil and cooling water components (i.e., filters, pumps, etc.). Other flow diagrams
 
may only depict the major component in the flow path, such as a heat exchanger
 
associated with a vendor supplied chiller package. The refrigerant loop
 
associated with the vendor supplied chiller unit is not depicted on the flow
 
diagram. Vendor drawings and vendor m anuals provide details associated with the vendor supplied equipment. In these cases, the vendor documents were
 
utilized to identify components, such as filters, that are subject to aging
 
management review. Examples of filters that were subject to an AMR that were
 
not shown on drawings are: Unit 1 reactor core isolation cooling system lube oil
 
filters; Unit 1 high pressure coolant injection system lube oil filters; and filters
 
associated with the refrigerant loop of heating ventilation and air condition
 
system chillers. 2.Browns Ferry has various maintenance procedures and work orders in place to assure that filters for safety related components are being monitored and
 
replaced as required to assure that equipment will perform its function. Some
 
examples of procedures used to repl ace the elements are: MPI-0-026-INS002 2-34 which is performed annually or 250 hour cumulative inspection, MPI-0-82-INS002 which performs the Standby Diesel Engine 24 month inspection, procedure 0-GI-
 
300-1 Attachment 15.11 which is the Monthly Ventilation Filter Check, repetitive
 
work orders done every 24 weeks, 0-SI-4.8.B.2-1 which is performed weekly, MPI-0-071-TRB001 and repetitive work order every 24 months, and MPI-0-073-
 
TRB001 and repetitive work order every 12 weeks. Browns Ferry has various
 
preventive maintenance procedures and work orders in place to assure that oil
 
and grease for safety related components are being monitored and replaced as
 
required to assure that equipment will perform its function. The following are
 
examples of procedures that are used for oil and grease replacement: QMDS
 
NUMBER MOV-001 (performed every 54 months), QMDS NUMBER MOV-002 (performed every 54 months), QMDS NUMBER MOV-003 (performed every 54 months), QMDS NUMBER MOT-001 (perfo rm oil samples every six months), QMDS NUMBER MOT-003 (performed at 24 and 36 month intervals), QMDS NUMBER PLN-003 (performed every 3 year s), EPI-0-000-MOT- 001 (Preventive Maintenance work orders are generated at various frequencies to add grease to
 
motors), EPI-0-000- MOT-002 (Preventive Maintenance work orders are
 
generated at various frequencies to add oil to motors), and MPI 000-LUB001 (Preventive Maintenance work orders are generated at various frequencies to
 
add grease to equipment). In addition, some components lubricants are
 
monitored and replaced based on oil analysis (predictive maintenance). 3.Our review did not identify any cases where oil, grease, or in scope filters were without proper plant procedures to exclude them as short lived.
In the initial response review, the staff was unable to find the applicant's response to RAI 2.3-2 acceptable. The applicant did not provide sufficient information to provide reasonable assurance
 
that all oil, grease and component filters are either outside the scope of license renewal or are
 
replaced based on a qualified life or specified time period. By letter dated May 18, 2005, the
 
applicant revised its response to state that it has various maintenance procedures and work
 
orders in place to assure that all filters for SR components are being monitored and replaced as
 
required to assure that the equipment will perform its function.
Based on its review, the staff found the applicant's revised response acceptable. There is reasonable assurance that all filters for SR components are covered by procedures or work
 
orders. Therefore, the staff's concerns described in RAI 2.3-2 are resolved.
In RAI 2.3-3, the staff stated that LRA Section 2.1.7.2 states that insulation at BFN does not have an intended function associated with the scoping requirements of 10 CFR 54.4(a)(1)
 
through (a)(3). However, there is insufficient information in the LRA and the UFSAR for the staff
 
to determine if the statement is valid at such a generic level. Insulation may be required for a
 
variety of reasons, e.g., systems efficiency, heat-load calculations, EQ purposes. etc. If the
 
insulation is relied upon for EQ purposes, the passive, long-lived insulation should be within the
 
scope of license renewal and subject to an AMR. Therefore, the staff requested that the
 
applicant provide a basis for not including any piping or equipment insulation within the scope of
 
license renewal.
On March 22, 2005, the staff held a teleconference with the applicant to discuss the treatment of insulation. In its response, by letter May 18, 2005, as modified by letter dated June 15, 2005, 2-35 the applicant stated that all the mechanical piping and equipment insulation contained in the SR structures as well as some NSR structures have been added to the scope of license renewal, since they meet the criteria of 10 CFR 54.4(a)(2) and (a)(3). Piping and equipment insulation
 
has the intended functions of insulate and integrity. The applicant stated that these intended
 
functions will be added to LRA Table 2.0.1. The applicant also stated that piping and equipment
 
insulation and insulation jacketing are component types that are subject to an AMR. LRA
 
Table 2.1.7.2 will be added to reflect these two component types and their intended functions.
Based on its review, the staff found the applicant's response to RAI 2.3-3 acceptable. The applicant placed all piping and equipment insulation that is within SR and some NSR structures
 
within the scope of license renewal and the insulation is subject to an AMR. Therefore, the
 
staff's concern described in RAI 2.3-s3 is resolved.
The staff reviewed LRA Section 2.3 and the applicant's responses to the RAIs and performed a plant audit. Based on this review, the staff found that the applicant's methodology for scoping and screening was well documented in an auditable and retrievable form at the plant site. The staff also found that the results of the audit on the system and the regulated event confirmed that there were no omissions of any components subject to an AMR for the audited systems. In the LRA Section 2.3 tables, the staff found that the results are consistent with the methodology and are acceptable. With the additional information obtained from responses to RAIs 2.3-2 and 2.3-3, the staff concluded that the applicant, while using a different methodology from that described in the review guidance of the SRP-LR, provided scoping and screening results and components subject to an AMR with no omissions. For other in-scope systems that were not audited at the plant site, the staff issued RAIs related to components that could be subject to an
 
AMR based on its review of the LRA, UFSAR, and site documentation.
In RAIs 2.1-2A(1) and (2) (described in SER Section 2.1) of the July 30, 2004, letter, the staff requested that the applicant describe the criteria used to determine that the integrity of in-scope piping functions (in the reactor building) is preserved if a potential age-related degradation failure occurred on the attached NSR piping (in the turbine building), given that the NSR piping is not in scope and piping is not anchored, and 2) explain how it determined that the SR piping (in the reactor building) is supported so that it would remain functional if a potential age-related degradation occurred on the NSR piping (in the turbine building) attached to it. In its response dated, October 18, 2004, the applicant committed to review the CLB requirements and identify the piping, supports and other components outside secondary containment required to maintain the structural integrity of the secondary containment. The applicant committed to performing this review prior to the period of extended operation. The deferral of this issue until prior to the period of extended operation is unacceptable. Therefore, the applicant performed the review, the results of which are documented in a letter dated May 31, 2005. The following mechanical systems only had systems boundary changes (i.e
., no new component types, materials, or environments were added) that affected either the scoping/screening or AMR review results in the LRA:
* main steam system
* auxiliary boiler system
* raw cooling water system
* station drainage system
* high pressure coolant injection system
* residual heat removal system 2-36
* radioactive waste system
* fuel pool cooling and cleanup system
* radiation monitoring system The following mechanical systems had systems boundary changes; however, for some of these systems, new component types were added that affected the scoping/screening results in the LRA. For all systems listed, new components, materials, or environments were added that affected the AMR review results in the LRA:
* condensate and demineralized water system
* feedwater system
* potable water system
* service air system
* containment system The effects of these changes are evaluated and discussed in the corresponding sections of the SER.In RAI 2.1-2A(3), described in SER Section 2.1, dated July 30, 2004, the staff requested that the applicant describe how the scoping and screening methodology ensured that NSR piping up to
 
the first equivalent anchor point was included within the scope of license renewal. The applicant
 
in its initial response to RAI 2.1.2A(3), dated September 3, 2004, committed to review the
 
seismic Class I piping boundaries and identify any additional piping segments and
 
supports/equivalent anchors that were needed to be placed within the scope of license renewal.
On September 24, 2004, in a teleconference between the staff and the applicant, the staff requested that the applicant provide additional information related to the methodology to be
 
utilized to ensure the liquid-filled NSR piping up to the first equivalent anchor point was
 
captured. By letter, dated January 31, 2005, the applicant stated that an extensive review was
 
performed that included verification of each seismic Class I boundary that typically falls into one
 
of the following categories: base-mounted equipment, pipe anchor, embedded piping segment, large run line, piping free end, flexible connection and overlap regions. Any identified piping, supports/equivalent anchors, or other components would be added to the scope of license
 
renewal as needed.
In a letter dated February 28, 2005, the applicant provided final status information and results from the calculation review requested by the staff. In enclosure 1 of the letter, the applicant
 
provided a summary of the following changes to the LRA as a result of this review.
The mechanical systems listed below had additional piping or components added to the scope of license renewal; however, even for those sy stems that had boundary changes as a result of the additional piping and components, no changes to the LRA were required, because the component-material-environment-program combi nation was already addressed in the LRA.
* condensate and demineralized water system
* standby liquid control system
* containment system
* reactor building closed cooling water system
* auxiliary decay heat removal system 2-37
* fuel pool cooling and cleanup system The following mechanical systems also had additional piping or components added to the scope of license renewal. However, for these systems with boundary changes because of the addition of piping and components, changes to the LRA were required, because the component-material-environment-program comb ination was not addressed in the LRA.
* CO 2 system
* sampling and water quality system
* off-gas system
* radioactive waste treatment system
* diesel generator starting air system The effect of these changes are evaluated and discussed in the corresponding sections of the SER (see Section 2.3.4.4 for details of RAIs 2.3.4.4-1 and 2.3.4.4-2).2.3.1  Reactor Coolant Systems In LRA Section 2.3.1, the applicant identified the structures and components of the reactor coolant systems (RCSs) that are subject to an AMR for license renewal.
The applicant described the supporting structures and components of the RCSs in the following sections of the LRA:
* 2.3.1.1reactor vessel
* 2.3.1.2reactor vessel internals
* 2.3.1.3reactor vessel vents and drains system
* 2.3.1.4reactor recirculation system The corresponding SER subsections, 2.3.1.1 - 2.3.1.4, present the staff's review findings.
2.3.1.1  Reactor Vessel 2.3.1.1.1  Summary of Technical Information in the Application In LRA Section 2.3.1.1, the applicant described the reactor vessel. The reactor vessel provides a container for the reactor core and the primary coolant in which the core is submerged. Each
 
unit has a separate reactor vessel. The reactor vessel is a pressure vessel with the geometry of
 
a vertically-aligned cylinder capped with hemispherical heads of welded construction. The
 
cylindrical shell and bottom hemispherical head of the reactor vessel are fabricated from
 
low-alloy carbon steel plate that is clad on the interior with weld overlay. The cylindrical shell is
 
clad with stainless steel and the bottom hemispherical head is clad with Inconel. The vessel top
 
head is not clad and is secured to the reactor vessel by studs and nuts. The vessel flanges are
 
sealed by two concentric metallic seal-rings that are designed for no detectable leakage through
 
the inner or outer seal at any operating condition.
The reactor vessel contains SR components that are relied upon to remain functional during, and following, DBEs to ensure the following intended functions:
2-38
* forms part of the reactor coolant pressure boundary
* provides physical support for the reactor core and the reactor vessel internals
* ensures a floodable volume and coolant distribution to mitigate accidents
* provides pressure boundary
* provides structural support In LRA Table 2.3.1.1, the applicant identified the following reactor vessel component types that are within the scope of license renewal and subject to an AMR: attachments and welds, closure
 
studs and nuts, heads, flanges, shell, nozzle safe ends, nozzles, other external attachments, penetrations, refueling bellows support skirt, stabilizer bracket, and support skirt and attachment
 
welds.2.3.1.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.1 and the UFSAR Section 4.2, 7.8, and Appendices J, K, and L using the evaluation methodology described in SER Section 2.3. The staff conducted its
 
review on the reactor vessel in accordance with the guidance described in SRP-LR Section 2.3,"Scoping and Screening Results - Mechanical Systems."In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR inaccordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omitted from the scope of license renewal any components with intended functions delineated under10 CFR 54.4(a). The staff then reviewed those com ponents that the applicant had identified as being within the scope of license renewal to verify that the applicant had not omitted any
 
passive and long-lived components that should be subject to an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
2.3.1.1.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In
 
addition, the staff performed a review to determine whether any components that should be
 
subject to an AMR had not been identified by the applicant. No omissions were identified. On
 
the basis of its review, the staff concluded that there is reasonable assurance that the applicant
 
had adequately identified the reactor vessel components that are within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and the reactor vessel components that are subject to
 
an AMR, as required by 10 CFR 54.21(a)(1).
2.3.1.2  Reactor Vessel Internals 2.3.1.2.1  Summary of Technical Information in the Application In LRA Section 2.3.1.2, the applicant described the reactor vessel internals. The reactor vessel internals are unique to each unit and provide partitions between regions within the reactor
 
vessel in order to provide proper coolant distribution, thereby allowing power operation without
 
fuel damage due to inadequate cooling. The reactor vessel internals also provide positioning
 
and support for the fuel assemblies, control rods, in-core flux monitors, and other components
 
to assure that control rod movement is not impaired. In addition, the reactor vessel internals 2-39 provide a floodable volume so that the core can be adequately cooled if there is an external reactor vessel breach in the nuclear system process barrier.
The reactor vessel internals consist of the following components:
* core shroud
* shroud head and steam separator assembly
* core support
* top guide
* fuel support pieces
* control rod guide tubes (control rod housing)
* jet pump assemblies
* steam dryers
* feed water spargers
* core spray lines and spargers
* vessel head spray nozzle
* differential pressure and liquid control line
* in-core flux monitor guide tubes
* startup neutron sources
* surveillance sample holders The reactor vessel contains SR components that are relied upon to remain functional during, and following, DBEs to ensure the following intended functions:
* provides physical support for the reactor core and the reactor vessel internals
* ensures a floodable volume and coolant distribution to mitigate accidents
* provides pressure boundary
* provides spray pattern
* provides structural support In LRA Table 2.3.1.2, the applicant identified the following reactor vessel internals component types that are within the scope of license renewal and subject to an AMR: core shroud and
 
plate; core spray lines and spargers; control rod drive (CRD) housing; dry tubes and guide
 
tubes; fuel support; jet pump assemblies; and top guide.
2.3.1.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.2 and UFSAR Section 3.3, 4.2, and Appendices J, K, and L using the evaluation methodology described in SER Section 2.3. The staff conducted its
 
review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omittedfrom the scope of license renewal any components with intended functions delineated under10 CFR 54.4(a). The staff then reviewed those com ponents that the applicant had identified as being within the scope of license renewal to verify that the applicant had not omitted any
 
passive and long-lived components that should be subject to an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
2-40 In reviewing LRA Section 2.3.1.2, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
In RAI 2.3.1.2-1, dated October 8, 2004, the staff requested the applicant to determine whether the scoping criteria of 10 CFR 54.4 (a) and the screening criteria of 10 CFR 54.21(a)(1) had
 
been properly applied. The staff requested the following:
In LRA Table 2.3.1.2, one of the intended functions of core spray spargers was appropriately identified as maintaining the spray pattern in a manner that all fuel
 
assemblies will be adequately cooled following a loss of coolant accident (LOCA). The
 
staff's understanding is that adequate long-term core cooling following a LOCA can only
 
be assured by retaining the original spray distribution over the core, which was assumed
 
for the CLB. In the SER for the Boiling Water Reactor Vessel and Internals Project (BWRVIP)-18 report, the staff had concluded that, when performing inspection of core
 
spray spargers, all boiling water reactor (BWR) plants must be treated as
 
geometry-critical plants. Furthermore, it is staff's understanding that the previous
 
BWRVIP designations of "geometry-tolerant" plants have been rescinded and all plants
 
are now considered to be "geometry-critical." Consequently, in order to assure adequate
 
cooling of the uncovered upper third of the core, the core spray system must provide
 
adequate spray distribution to all assemblies in the core. The staff also believes that
 
leakage through sparger and piping cracks, as well as repairs and potential blockage of
 
spray nozzles must be considered in assessing the core spray distribution. As a result, it
 
is essential that spraying water on the fuel assemblies in a pattern that was originally
 
designed must be maintained, and that the applicant's aging management activities
 
provide reasonable assurance that the original spray distribution will be preserved during
 
the period of extended operation.
On the basis of the above discussion, the staff requests the applicant to affirm that when performing inspection of core spray spargers, the BFN plants are inspected in
 
accordance to the requirements for the "geometry-critical" plants, as required by the staff SER for the BWRVIP-18 report; and that the original spray pattern assumed for the CLB
 
will be preserved during the extended period of operation.
In its response, by letter dated November 3, 2004, the applicant stated that BFN is performing inspections as required by the BWRVIP-18 report, as modified by January 11, 1999, letter, which requires that core spray spargers of all plants receive the same type of inspection. The
 
applicant also stated that, based on the Chemistry Control Program and that the nozzles are
 
constructed of a stainless steel material, corrosion is not a credible aging mechanism to cause
 
flow blockage.
Based on its review, the staff found the applicant's response to RAI 2.3.1.2-1 acceptable. The applicant included the subject components and their intended functions as within scope
 
requiring an AMR. Therefore, the staff's concern described in RAI 2.3.1.2-1 is resolved.
Recent industry experience of steam dryer failures at operating BWRs and the potential of steam dryers to generate loose parts that can degrade SR components have necessitated that
 
the staff reconsider whether steam dryers should be within the scope of license renewal, in
 
accordance with 10 CFR 54.4(a)(2), and require aging management. Although the steam dryer
 
does not perform an SR function, the steam dryer must maintain its structural integrity to 1 TVA by letter dated January 7, 2005, agreed to decouple the power uprate licensing request from License Renewal Application. The safety review of this item will be further evaluated as part of the EPU review.
2-41 support emergency core cooling system (ECCS) operation, and also to prevent the occurrence of loose parts in the reactor vessel or steam lines that could adversely affect plant operation.
In RAI 2.3.1.2-2, dated October 8, 2004, the staff requested the applicant to provide the following additional information:
* Whether the steam dryer designs at BFN and Quad Cities are similar. If not, the applicant was requested to describe the significant differences between the two designs
 
that support the conclusion that steam dryer failures similar to those that occurred at
 
Quad Cities are unlikely to develop at the BFN steam dryers following power uprate.
* Describe any actions, including analysis, that will be performed to confirm that extended power uprate 1 conditions will not generate loose parts from the steam dryer.
In its response, by letter November 3, 2004, the applicant stated that the steam dryers had been added within the scope of license renewal on the basis of 10 CFR 54.4(a)(2) scoping criterion.
 
In addition, the applicant provided the following information to compare the configuration of the
 
steam dryers at BFN with the configuration of the steam dryers at the Quad Cities Nuclear
 
Power Station plants.
There are three general types of steam dryer configurations:
1.BWR/3-style steam dryers with a square hood and internal braces (This is the configuration at Quad Cities). 2.BWR/4-style steam dryers that have slanted hoods (This is the configuration at BFN). 3.BWR/5 and later steam dryer designs that incorporate curved hoods to optimize the steam flow.
Basically the BFN dryer is a slanted hood design, which is much less susceptible to vibration-induced failures than the square hood design of the Quad Cities dryers. General
 
Electric Corporation (GE) has conducted fini te element model analysis, which documents that the square hood is more susceptible to operating stresses. The forcing function for the dryer
 
loads has been identified as being primarily acoustic loads that originate in the steam lines. The
 
BWRVIP and the industry have efforts underway to develop methods to measure and document
 
the amount of additional loads that may be placed on the dryer as the result of uprated
 
conditions. The applicant further stated that it will follow the BWRVIP guidelines for the
 
inspection and evaluation of the dryers to insure their future integrity under uprated operating
 
conditions.
The applicant added the subject components within the scope requiring an AMR and the staff's concerns described in RAI 2.3.1.2-2 are partly resolved. However, the subject of the second
 
question of the staff RAI is currently being reviewed as part of the ongoing EPU review (see
 
footnote previous page).
2-42 2.3.1.2.3  Conclusion The staff reviewed the LRA and RAI responses to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff performed a review to determine whether any components that
 
should be subject to an AMR had not been identified by the applicant. No omissions were
 
identified. On the basis of its review, the staff concluded that there is reasonable assurance that
 
the applicant had adequately identified the reactor vessel internals components that are within
 
the scope of license renewal, as required by 10 CFR 54.4(a), and the reactor vessel internals
 
components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.1.3  Reactor Vessel Vents and Drains System 2.3.1.3.1  Summary of Technical Information in the Application In LRA Section 2.3.1.3, the applicant described the reactor vessel vents and drains system. The reactor vessel vents and drains system consists of the valves and piping connected to the
 
reactor coolant pressure boundary (RCPB). This includes the reactor vessel head vent piping, the reactor vessel bottom head drain piping, and the blowdown piping from the main steam
 
relief valves (MSRVs) to the pressure suppr ession chamber. The system is unique to each unit and shares no components with other units. All piping and components are located within the
 
primary containment.
The reactor vessel vents and drains system c ontains SR components that are relied upon to remain functional during, and following, DBEs to ensure the following intended functions:
* provides a path for the main steam (MS) system, safety relief valves (SRVs), and steam blowdown to the primary containment suppression pool
* provides RCPB
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.1.3, the applicant identified the following reactor vessel vents and drains system component types that are within the scope of license renewal and subject to an AMR:
bolting, fittings, RCPB fittings, piping, RCPB piping, valves, and RCPB valves.
2.3.1.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.3 and UFSAR Sections 4.11, 7.8, and C.2 using the evaluation methodology described in SER Section 2.3. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omittedfrom the scope of license renewal any components with intended functions delineated under10 CFR 54.4(a). The staff then reviewed those com ponents that the applicant had identified as 2-43 being within the scope of license renewal to verify that the applicant had not omitted any passive and long-lived components that should be subject to an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
2.3.1.3.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In
 
addition, the staff performed a review to determine whether any components that should be
 
subject to an AMR had not been identified by the applicant. No omissions were identified. On
 
the basis of its review, the staff concluded that there is reasonable assurance that the applicant
 
had adequately identified the reactor vessel vents and drains system components that are
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and the reactor vessel
 
vents and drains system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.1.4  Reactor Recirculation System 2.3.1.4.1  Summary of Technical Information in the Application In LRA Section 2.3.1.4, the applicant described the reactor recirculation system. The reactor recirculation system is unique to each unit and consists of two piping loops connected to, but
 
external to, the reactor vessel. Each loop has a single, variable speed, motor driven pump with
 
pump suction and discharge valves. Each pump takes suction from the reactor vessel
 
downcomer region and discharges into a manifold that supplies flow to ten jet pumps contained
 
within the reactor vessel. During normal operations, the system provides sufficient subcooled
 
water to the reactor core to maintain the normal core operating temperatures. The system also
 
provides control of reactor power by varying recirculation flow during normal operations. In
 
addition, the system provides a flow path for the low pressure coolant injection flow from the RHR system to the reactor vessel during design basis accidents (DBAs) and a flow path to and
 
from the RHR system for removal of decay heat at low temperatures.
The reactor recirculation system contains SR components that are relied upon to remain functional during, and following DBEs. The failure of NSR SSCs in the reactor recirculation
 
system could prevent the satisfactory accomplishm ent of an SR function. In addition, the reactor recirculation system performs functions that support fire protection, EQ, and ATWS.
The intended functions within the scope of license renewal include the following:
* provides RCPB
* provides a primary containment boundary
* restricts flow
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.1.4, the applicant identified the following reactor recirculation system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings, flexible connectors, heat exchangers, piping, RCPB piping, pumps, 2-44 reactor coolant pumps, restricting orifices, RCPB restricting orifices, strainers, tanks, tubing, valves, and RCPB valves.
2.3.1.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.4 and UFSAR Sections 3.7.6, 4.3, 5.2.3, 7.8, 7.9, and 7.19 using the evaluation methodology described in SER Section 2.3. The staff conducted its
 
review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omittedfrom the scope of license renewal any components with intended functions delineated under10 CFR 54.4(a). The staff then reviewed those com ponents that the applicant had identified as being within the scope of license renewal to verify that the applicant had not omitted any
 
passive and long-lived components that should be subject to an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.1.4, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results. The
 
staff requested the applicant to determine whether the scoping criteria of 10 CFR 54.4 (a) and
 
the screening criteria of 10 CFR 54.21(a)(1) have been properly applied.
In RAI 2.3.1.4-1, dated October 8, 2004, the staff stated that in LRA Table 2.3.1.4, for the reactor recirculation system, and for other syst ems, for example, the containment inerting system, heat exchangers have been identified as a component type within the scope of license renewal. However, for these heat exchangers, the pressure boundary function was identified as
 
the only intended function requiring aging management. Therefore, the staff requested the
 
applicant to clarify why the heat transfer function was not also identified as an intended function
 
that needs to be maintained during the extended period of operation by assigning appropriate
 
aging management program (AMP) for it.
In its response, by letter dated November 3, 2004, the applicant stated that the heat exchangers associated with LRA Table 2.3.1.4 are the heat exchangers shown on license renewal drawings
 
2-47E844-2-LR and 3-47E817-2-LR. The shell sides of these heat exchangers are within the
 
scope of license renewal for secondary containment as a pressure boundary for the raw water
 
system. These heat exchangers are not SR, but the tube side is within the scope of license
 
renewal to satisfy 10 CFR 54.4(a)(2) requirements only. Therefore, these heat exchangers are
 
not credited for their heat transfer function.
Based on its review, the staff found the applicant's response to RAI 2.3.1.4-1 acceptable. The applicant provided the justification as to why the heat transfer function of the subject
 
components need not be within the scope of license renewal requiring aging management.
 
Therefore, the staff's concern described in RAI 2.3.1.4-1 is resolved.
2.3.1.4.3  Conclusion
 
The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI response described above to determine whether any SSCs that should be within the scope of license
 
renewal had not been identified by the applicant. No omissions were identified. In addition, the 2-45 staff performed a review to determine whether any components that should be subject to an AMR had not been identified by the applicant. No omissions were identified. On the basis of its
 
review, the staff concluded that there is reasonable assurance that the applicant had adequately
 
identified the reactor recirculation system components that are within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and the reactor recirculation system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2  Engineered Safety Features In LRA Section 2.3.2, the applicant identified the structures and components of the engineered safety features (ESFs) that are subject to an AMR for license renewal.
The applicant described the supporting structures and components of the ESF in the following sections of the LRA:
* 2.3.2.1containment systems
* 2.3.2.2standby gas treatment system
* 2.3.2.3high pressure coolant injection system
* 2.3.2.4residual heat removal system
* 2.3.2.5core spray system
* 2.3.2.6containment inerting system
* 2.3.2.7containment atmosphere dilution system The corresponding SER subsections, 2.3.2.1 - 2.3.2.7, present the staff's review findings with respect to the ESF for BFN.
2.3.2.1  Containment System 2.3.2.1.1  Summary of Technical Information in the Application In LRA Section 2.3.2.1, the applicant described the containment system. The containment system includes the following subsystems: t he primary containment and primary containment isolation system, the secondary containment, and the reactor building ventilation system. The scoping and screening results for the primary containment isolation valves for the various
 
processes are presented within their respective systems. The results of the scoping and
 
screening evaluations for the other components with in the containment system including valves, piping, penetrations, structural steel, that are essential for primary containment integrity, are
 
presented in other sections of this SER.
The primary containment system for each uni t employs an independent pressure suppression that houses the reactor vessel, reactor coolant recirculation loops, and other branch
 
connections of systems that form the RCPB. The Mark I containment is a pressure suppression
 
system design, which consists of a drywell and a pressure suppression chamber that is
 
alternatively referred to as the "torus" or "wetwell." The Mark I pressure suppression system also
 
contains a connecting vent system between the drywell and the pressure suppression chamber, isolation valves, equipment for establishing and maintaining a pressure differential between the
 
drywell and pressure suppression chamber, and other service equipment. Air that is transferred
 
to the pressure suppression chamber pressu rizes the chamber and is subsequently vented to the drywell to equalize the pressure between the two vessels, and it is necessary in the event of 2-46 a process system piping failure within the drywell.
Cooling systems are provided to remove heat from the drywell and the water from the pressure suppression chamber, thus cooling and controlling the pressure in the primary containment under accident conditions. In addition, valves and flowpaths are provided to control the internal and the torus/drywell differential
 
pressure. If long-term, post-accident cooling capability is lost, resulting in a pressure increase
 
that would jeopardize the structural integrity of the primary containment, a hardened wetwell
 
vent to the plant stack can be opened to relieve the pressure increase.
The containment system also includes the secondary containment system. The secondary containment system provides an essentially l eak-tight envelope for any radiation release from the primary containment during DBEs. The sec ondary containment system also provides a primary envelope for radiation releases when the primary containment systems are open for refueling or maintenance.
This structure is divided into three reactor zones and a refueling zone. Each reactor zone houses the reactor, the primary containment, and the individual unit's ECCS. The structure also
 
contains a spent fuel storage pool for each individual unit. The refueling zone allows continuous
 
access to the three spent fuel storage pools and the reactor vessel for refueling and servicing.
The reactor building ventilation system is also included within the containment system. The reactor building is heated, cooled, and ventilated during normal and shutdown operations by a
 
circulating air system. The reactor building vent ilation system is shut down and isolated when a zone of secondary containment is isolated and connected to the standby gas treatment (SGT)
 
system. The ventilation system has supply fans t hat provide makeup air that is filtered, heated by hot water coils for winter heating, and cooled by evaporative coolers for summer cooling. Air
 
is exhausted from the reactor building by exhaust fans located on the building's roof. Air from
 
each zone is monitored before release. The reactor building ventilation system also includes
 
area cooling units for areas containing ECCS components.
The containment system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the containment system could prevent
 
the satisfactory accomplishment of an SR function. In addition, the containment system
 
performs functions that support fire protection, EQ, and SBO.
The intended functions within the scope of license renewal include the following:
* provides a primary containment boundary
* provides a vacuum relief system (v acuum breaker valves) to prevent drywell or suppression chamber (torus) negative pr essure from damaging the containment structure
* provides air-operated re-closure of the inboard reactor building to the torus vacuum breakers
* provides pressure suppression by cooling/condensation of the safety relief valves (SRVs) steam from boiler drains and vents system and reactor core isolation cooling (RCIC) system and high pressure coolant in jection (HPCI) system turbine exhaust steam
* accepts HPCI and RCIC system pump minimum bypass flow 2-47
* provides a water supply to the RCIC syst em, HPCI system, core spray (CS) system, and RHR system pumps
* provides forced air cooling for t he RHR system and the CS system pump motors
* provides a secondary containment boundary (passive functions)
* provides a pressure boundary of cont ainment system components connected to the control air system that must maintain the pressure boundary in support of supplying
 
containment atmosphere dilution (CAD) to the main steam safety relief valves (MSRVs)
* provides fire dampers that are required for unit operation
* provides debris protection
* provides fire barrier
* provides for heat transfer
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.2.1, the applicant identified the following containment system component types that are within the scope of license renewal and subject to an AMR: bolting, ductwork, heat exchangers, fire dampers, flexible connectors, fittings, piping, strainers, traps, tubing, and valves.2.3.2.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.1, LRA Appendix F, and UFSAR Sections 5.2, 5.3, 5.3.3.2, 5.3.3.6, and 7.3, F.7.1, and F.7.11 using the evaluation methodology described in SER
 
Section 2.3. The staff conducted its review in accordance with the guidance described in
 
SRP-LR Section 2.3.
In conducting the review, the staff reviewed the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.2.1, the staff identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. Therefore, by letter dated October 8, 2004, the staff issued an RAI concerning the specific issues to
 
determine whether the applicant had properly applied the scoping criteria of 10 CFR 54.4(a) and
 
the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff's RAIs
 
and the applicant's related responses.
In RAI 2.3.2.1-1, the staff requested that the applicant clarify whether all the system components such as, but not limited to, air cooling unit housings, dampers and damper 2-48 housings, cooling coil housings, valve bodies, and screens for intake and exhaust structures are within the scope of license renewal in accordance with 10 CFR 54.4(a), and subject to an AMR
 
in accordance with 10 CFR 54.21(a)(1).
In its response, by letter dated November 3, 2004, and supplemented by a letter dated December 3, 2004, the applicant stated that all applicable system components consisting of air
 
cooling unit housings, dampers and damper housings, cooling coil housings, and valve bodies
 
are within the scope of license renewal in accordance with 10 CFR 54.4(a), and subject to an
 
AMR in accordance with 10 CFR 54.21(a)(1) for the RBVS (containment). LRA Section 2.3.5, "Notes Associated with the Section 2.3 Tables," is revised to reflect these component types and, therefore, is part of "Component Types" in LR A Table 2.3.2.1, "Containment System," and LRA Table 3.2.2.1, "Containment System-Summary of Aging Management Evaluation." The applicant also stated that the RBVS contains an intake plenum that contains louvers with screens and
 
that these components perform no license renewal function; therefore, these components are not within the scope of license renewal.
Based on the review, the staff found the applicant's response to RAI 2.3.2.1-1 acceptable. The applicant clarified that all applicable system components consisting of air cooling unit housings, dampers and damper housings, cooling coil housings, and valve bodies are within the scope of
 
license renewal, and subject to an AMR for the RBVS and are already included in "Component
 
Types" in LRA Tables 2.3.2.1 and 3.2.2.1. Since the RBVS intake plenum with louvers and
 
screens performs no license renewal function, these components are not within the scope of
 
license renewal. Therefore, the staff's concern described in RAI 2.3.2.1-1 is resolved.
2.3.2.1.3  Conclusion
 
The staff reviewed the LRA and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the containment system
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the containment system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.2.2  Standby Gas Treatment System 2.3.2.2.1  Summary of Technical Information in the Application In LRA Section 2.3.2.2, the applicant descri bed the SGT system. The SGT system is shared between Units 1, 2, and 3. The SGT system consists of a suction duct system, three filter trains and blowers, and a discharge vent system. The co mmon suction duct system takes suction from the normal ventilation exhaust duct of each of the three reactor zones and from the refueling
 
zone that is independent of the normal ventilation system. Each filter train contains a moisture
 
separator, a heater, a pre-filter, an upstream high efficiency particulate air (HEPA) filter, a
 
charcoal filter, and a downstream HEPA filter. These three filter trains and blowers are arranged
 
in parallel. The three blowers share a common discharge header that discharges to the plant 2-49 stack 600 feet in elevation. The filter trains and blowers are located in the SGT building. The SGT system is normally in standby operati on and will start automatically, when required.
The SGT system contains SR components that are relied upon to remain functional during, and following, DBEs. In addition, the SGT system performs functions that support EQ.
The intended functions within the scope of license renewal include the following:
* maintains negative pressure in the secondary containment on the primary containment system group six isolation signal
* filters airborne particulates and gases including those from the HPCI and CAD systems prior to discharge to the off-gas system
* maintains negative pressure in secondary containment on primary containment system signal due to radiation monitoring system refueling zone high radiation signal
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.2.2, the applicant identified the following SGT system component types that are within the scope of license renewal and subject to an AMR: bolting, ductwork, fittings, flexible connectors, piping, tubing, and valves.
2.3.2.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.2 and LRA Appendix F and UFSAR Sections 5.3.3, 7.12.5, and F.7.18 using the evaluation methodology described in SER Section 2.3. The staff
 
conducted its review in accordance with the guidance described in SRP-LR Section 2.3.
In conducting the review, the staff reviewed the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.2.2, the staff identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. Therefore, by letter dated October 8, 2004, the staff issued an RAI concerning the specific issues to
 
determine whether the applicant had properly applied the scoping criteria of 10 CFR 54.4(a) and
 
the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff's RAI
 
and the applicant's responses.
In RAI 2.3.2.2-1, the staff requested the applicant to clarify whether all the system's components such as, but not limited to, fan housings, filter housing, damper housing, valve bodies, screens
 
for intake and exhaust structures, and all other applicable components of the system, including 2-50 duct sealants, wall sealants, pressure boundary sealants are within the scope of license renewal in accordance with 10 CFR 54.4(a), and subject to an AMR in accordance with
 
10 CFR 54.21(a)(1).
In its response, by letter dated November 3, 2004, and supplemented by a letter dated December 3, 2004, the applicant stated that all applicable system components consisting of fan
 
housings, filter housing, damper housing, valve bodies including duct sealants, wall sealants, and pressure boundary sealants are within the scope of license renewal in accordance with
 
10 CFR 54.4(a), and subject to an AMR in accordance with 10 CFR 54.21(a)(1) for the SGT
 
system. The applicant also stated that structural sealants, such as those required to maintain
 
the secondary containment at a negative pressure with respect to the adjacent areas, are
 
contained in LRA Section 3.5.2.1.2 and Table 3.5.2.2 as component types "Compression Joints
 
and Seals" and "Caulking and Sealants," and that the SGT system does not contain air
 
intake/exhaust structures with screens (SGT system exhausts to the reinforced concrete
 
chimney (plant stack) as addressed in LRA Section 2.4.6.1).
In LRA Section 2.3.5, "Notes Associated with the Section 2.3 Tables," "Component Types" are revised to reflect these components and, therefore, are part of LRA Table 2.3.2.2, "Standby Gas
 
Treatment System" and LRA Table 3.2.2.2, "Standby Gas Treatment System-Summary of Aging Management Evaluation."
Based on its review, the staff found the applicant's response to RAI 2.3.2.2-1 acceptable. The applicant clarified that all applicable system components consisting of fan housings, filter
 
housing, damper housing, valve bodies, and all other applicable components of the system, including duct sealants, wall sealants, and pressure boundary sealants are within the scope of
 
license renewal, and subject to an AMR for the SGT system and are already included in "Component Types" in LRA Tables 2.3.2.2 and 3.2.2.2. Therefore, the staff's concern described
 
in RAI 2.3.2.2-1 is resolved.
2.3.2.2.3  Conclusion
 
The staff reviewed the LRA and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the SGT system components
 
that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the SGT
 
system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.2.3  High Pressure Coolant Injection System 2.3.2.3.1  Summary of Technical Information in the Application In LRA Section 2.3.2.3, the applicant described the HPCI system. The HPCI system, in conjunction with the other ECCSs, limits the peak fuel clad temperature, over the complete
 
spectrum of possible break sizes in the RCPB, during design-basis accidents. The HPCI system
 
also provides adequate core cooling for small breaks and depressurizes the reactor coolant
 
systems to allow low-pressure coolant injection and core spray flow. In addition, the HPCI 2-51 system provides reactor vessel make-up, pressure control, and decay heat removal during regulated events.
Each unit has an individual HPCI system and no components are shared; however, each unit's HPCI pump may take suction from any unit's condensate storage tank. The HPCI system
 
consists of a single steam turbine-driven pump. The steam supply for the turbine comes from
 
the MS system and exhausts to the suppre ssion pool. The pump takes suction from the condensate storage tank, or the suppression pool, and discharges into the reactor vessel, through the feedwater (FW) system. A full-flow test line to the condensate storage tank is
 
provided. During normal operation, the HPCI system is in standby. The HPCI system automatically starts if there is high pressure in the drywell or a low-water level in the reactor vessel.The HPCI system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the HPCI system could prevent the satisfactory
 
accomplishment of an SR function. In addition, the HPCI system performs functions that support
 
fire protection, EQ, and SBO.
The intended functions within the scope of license renewal include the following:
* provides an RCPB during HPCI system standby and operation
* provides a primary containment boundary during HPCI system standby and operation
* limits the loss of coolant through the HPCI system steam supply line break (passive, flow restrictor built into the steam line)
* provides a secondary containment boundary
* establishes a main steam safety isolation valve (MSIV) leakage pathway to the condenser
* provides coolant to the reactor vessel until it can be manually run in the condensate storage tank to condensate storage tank recirculation mode for pressure relief and
 
decay heat
* provides debris protection
* provides for flow distribution
* restricts flow
* provides for heat transfer
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.2.3, the applicant identified the following HPCI system component types that are within the scope of license renewal and subject to an AMR: bolting, condenser, expansion
 
joint, fittings, RCPB fittings, flexible connectors, gland seal blower, heat exchangers, piping, RCPB piping, pumps, restricting orifice, RCPB restricting orifice, strainers, tanks, traps, tubing, turbines, valves, and RCPB valves.
2-52 2.3.2.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.3 and UFSAR Sections 5.2.3, 5.3, 6.3, 6.4.1, and 7.4 using the evaluation methodology described in SER Section 2.3. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omittedfrom the scope of license renewal any components with intended functions delineated under10 CFR 54.4(a). The staff then reviewed those com ponents that the applicant had identified as being within the scope of license renewal to verify that the applicant had not omitted any
 
passive and long-lived components that should be subject to an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
2.3.2.3.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In
 
addition, the staff performed a review to determine whether any components that should be
 
subject to an AMR had not been identified by the applicant. No omissions were identified. On
 
the basis of its review, the staff concluded that there is reasonable assurance that the applicant
 
had adequately identified the HPCI system components that are within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and the HPCI system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.2.4  Residual Heat Removal System 2.3.2.4.1  Summary of Technical Information in the Application In LRA Section 2.3.2.4, the applicant described the RHR system. Each unit has two RHR system loops and each loop has two RHR pumps and two RHR heat exchangers. The pump suction header and the heat exchanger discharge header of one loop in Unit 1 and one loop in
 
Unit 2 can be cross-connected. A similar cross-connection is provided between Unit 2 and
 
Unit 3. The RHR system provides a number of functions that are manually initiated. The RHR system provides shutdown cooling during normal oper ations and regulated events. The RHR system, in conjunction with the other ECCSs, also provides core flooding to limit the peak fuel clad
 
temperatures over the complete spectrum of possible break sizes in the RCPB during
 
design-basis accidents.
Provisions are provided within the RHR system, for both makeup and reject, to maintain the suppression pool level within the required limits. Cross-connections with the fuel pool cooling
 
system allow the RHR heat exchangers to s upplement heat removal and provide a permanent source of makeup water for the spent fuel pool.
The RHR contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the RHR could prevent the satisfactory 2-53 accomplishment of an SR function. In addition, the RHR performs functions that support fire protection, EQ, and SBO.
The intended functions within the scope of license renewal include the following:
* provides suppression pool water cooling to maintain the suppression pool water temperature below limits to assure that pump net positive suction head requirements are met and that complete condensation of blowdown steam from a design-basis LOCA can
 
be expected
* provides spray to drywell and torus for containment cooling and lowering of containment pressure under post-accident conditions
* provides a secondary containment boundary and a pressure boundary interface with the condensate ring header
* provides RCPB
* provides RHR system piping flow path for transmission of condensate and demineralized water system water supply to HPCI syst em piping upstream of HPCI system pump
* provides RHR system piping flow pat h from the HPCI system pump minimum flow coolant to the main RHR system heat exchangers
* provides debris protection
* provides for flow distribution
* restricts flow
* provides for heat transfer
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.2.4, the applicant identified the following RHR system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings, heat exchangers, piping, RCPB piping, pumps, restricting orifice, strainers, tubing, valves, and
 
RCPB valves.
2.3.2.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.4 and UFSAR Sections 3.3, 4.1, 4.8, 5.2.3, 5.3, 6.4.4, 7.3, 7.4, 7.18, 9.2, 10.5, 10.9, 10.10, 10.17, F7.9, F7.15, and F7.16 using the evaluation
 
methodology described in SER Section 2.3. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omittedfrom the scope of license renewal any components with intended functions delineated under10 CFR 54.4(a). The staff then reviewed those com ponents that the applicant had identified as being within the scope of license renewal to verify that the applicant had not omitted any 2-54 passive and long-lived components that should be subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.2.4.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In
 
addition, the staff performed a review to determine whether any components that should be
 
subject to an AMR had not been identified by the applicant. No omissions were identified. On
 
the basis of its review, the staff concluded that there is reasonable assurance that the applicant
 
had adequately identified the RHR system components that are within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and the RHR system components that are subject to
 
an AMR, as required by 10 CFR 54.21(a)(1).
2.3.2.5  Core Spray System 2.3.2.5.1  Summary of Technical Information in the Application In LRA Section 2.3.2.5, the applicant described the CS system. The CS system, in conjunction with the other ECCSs, provides spray cooling to the reactor core to limit the peak fuel clad
 
temperature over the complete spectrum of possible break sizes in the RCPB during
 
design-basis accidents. Each individual unit contains a separate CS system with two
 
independent loops. Each loop has two pumps that can pump water from the suppression pool
 
directed into the reactor vessel to the spray headers located above the core and within the core
 
shroud. Some CS system components are located within the reactor vessel; these components
 
are evaluated in the reactor vessel internals section of this SER.
Full-flow pump test capability is provided by discharge line to the suppression pool. During normal operation, the CS system is in standby and can be started automatically, when required.
Full-flow suction lines from the condensate storage tanks penetrate the secondary containment
 
and provide a suction flow path for the RCIC and HPCI systems.
The CS system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the CS system could prevent the satisfactory
 
accomplishment of an SR function. In addition, the CS system performs functions that support
 
EQ.The intended functions within the scope of license renewal include the following:
* supplies cooling water to the reactor (automatic initiation)
* provides RCPB
* provides a primary containment boundary
* provides a secondary containment boundary and pressure boundary interface with the condensate system ring header
* provides debris protection
* restricts flow 2-55
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.2.5, the applicant identified the following CS system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings, piping, RCPB piping, pumps, restricting orifice, RCPB restricting orifice, strainers, tanks, tubing, valves, and RCPB valves.
2.3.2.5.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.5 and the UFSAR Sections 4.4, 5.2, 5.3, 6.4.3, 7.3, 7.4, 7.8, 10.10, and 11.7 using the evaluation methodology described in SER Section 2.3. The staff
 
conducted its review in accordance with the guidance described in the SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omittedfrom the scope of license renewal any components with intended functions delineated under10 CFR 54.4(a). The staff then reviewed those com ponents that the applicant had identified as being within the scope of license renewal to verify that the applicant had not omitted any
 
passive and long-lived components that should be subject to an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.2.5, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated October 8, 2004, the staff issued an RAI concerning
 
the specific issues to determine whether the applicant had properly applied the scoping criteria
 
of 10 CFR 54.4 (a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAIs and the applicant's related responses.
In RAI 2.3.2.5-1, the staff stated that the low pressure coolant injection (LPCI) coupling was identified in the BWRVIP-06 report as an SR component. It appears, however, that the
 
component was not identified in the LRA as requiring an AMR. Therefore, the staff requested
 
the applicant to justify its exclusion from aging management and to submit an AMR for the subject component.
In its response, by letter dated November 3, 2004, the applicant stated that BFN does not contain a LPCI coupling; therefore this component was not identified in the LRA. Therefore, the
 
staff's concern described in RAI 2.3.2.5-1 is resolved.
2.3.2.5.3  Conclusion
 
The staff reviewed the LRA and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the CS system components 2-56 that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CS system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.2.6  Containment Inerting System 2.3.2.6.1  Summary of Technical Information in the Application In LRA Section 2.3.2.6, the applicant described the containment inerting system. The containment inerting system provides the capability to measure oxygen and hydrogen concentrations in the primary containment following an accident. A separate oxygen and
 
hydrogen monitoring system, with two sampli ng loops, is provided for each unit. The loops have pumps that pump the drywell or torus atmosphere past the hydrogen and oxygen sensors and back to the torus. In the event of an accident, the containment inerting system would be
 
manually started.
The containment inerting system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the containment inerting
 
system could prevent the satisfactory accomp lishment of an SR function. In addition, the containment inerting system performs functions that support EQ.
The intended functions within the scope of license renewal include the following:
* provides oxygen and hydrogen gas analyzers and indicators to monitor gas concentrations inside the primary containment in support of CAD system operation,
* provides a primary containment boundary
* provides a secondary containment boundary
* provides debris protection
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.2.6, the applicant identified the following containment inerting system component types that are within the scope of license renewal and subject to an AMR: bolting, flexible connectors, heat exchangers, fittings, piping, pumps, strainers, traps, tubing, and valves.2.3.2.6.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.6, LRA Appendix F, and UFSAR Section 5.2.6 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
In conducting the review, the staff reviewed the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant 2-57 had identified as being within the scope of license renewal to verify that the applicant had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.2.6, the staff identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. Therefore, by the letter dated October 8, 2004, the staff issued an RAI concerning the specific issues to
 
determine whether the applicant had properly applied the scoping criteria of 10 CFR 54.4(a) and
 
the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff's RAI
 
and the applicant's response.
In RAI 2.3.2.6-1, the staff requested that the applicant clarify whether the system components such as piping, valves, and equipment between FCV-76-17 and PC-V67-14, including the
 
downstream bypass line after BYV-76-542, and between CKV-76-653 and CKV-76-659
 
depicted on LRA drawings 47E860-1-LR for Units 1, 2, and 3, are within the scope of license
 
renewal in accordance with 10 CFR 54.4(a), and subject to an AMR in accordance with
 
10 CFR 54.21(a)(1).
In its response, by letter dated November 3, 2004, the applicant stated that all applicable system components between primary containm ent isolation valve FCV-76-17 and secondary containment isolation valve PCV-76-14, and bet ween primary containment isolation valve CKV-76-653 and secondary containment isolation valve CKV-76-659 are not within scope for
 
10 CFR 54.4(a)(1). They are not within scope for 10 CFR 54.4(a)(3) since they are not required
 
for any of the regulated events. Also, since these components are not liquid filled, they do not
 
meet the criteria of 10 CFR 54.4(a)(2).
Based on its review, the staff found the applicant's response to RAI 2.3.2.6-1 acceptable. The applicant clarified why the above system components are not within the scope of license
 
renewal. The applicant identified those portions of the containment inerting system that meet the scoping requirements of 10 CFR 54.4 and included them within the scope of license renewal
 
in LRA Section 2.3.2.6. The applicant also included containment inerting system components
 
that are subject to an AMR in accordance with 10 CFR 54.4(a) and 10 CFR 54.21(a) (1) in LRA
 
Table 2.3.2.6, "Containment Inerting System,"
and in LRA Table 3.2.2.6, "Containment Inerting System-Summary of Aging Management Evaluation.
" Therefore, the staff's concern described in RAI 2.3.2.6-1 is resolved.
2.3.2.6.3  Conclusion
 
The staff reviewed the LRA, the accompany scoping boundary drawings, and the RAI response described above to determine whether any SSCs that should be within the scope of license
 
renewal had not been identified by the applicant. No omissions were identified. In addition, the
 
staff performed a review to determine whether any components that should be subject to an
 
AMR had not been identified by the applicant. No omissions were identified. On the basis of its
 
review, the staff concluded that there is reasonable assurance that the applicant had adequately
 
identified the containment inerting system components that are within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and t he containment inerting system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-58 2.3.2.7  Containment Atmosphere Dilution System 2.3.2.7.1  Summary of Technical Information in the Application In LRA Section 2.3.2.7, the applicant described the CAD system. The CAD system is shared between Units 1, 2, and 3. The system consists of two trains, each of which is capable of
 
supplying nitrogen through separate piping systems, to the drywell and suppression chamber.
 
The system is in standby during normal operat ion and is started manually when required.
The CAD system contains SR components that are relied upon to remain functional during, and following, DBEs. In addition, the CAD system performs functions that support fire protection, EQ, and SBO.
The intended functions within the scope of license renewal include the following:
* provides for dilution of the primary containment atmosphere with nitrogen after a LOCA to maintain hydrogen and oxygen gas concentrations below a level that could produce a
 
combustible mixture (five percent oxygen by volume)
* provides a primary containment boundary
* provides a secondary containment boundary
* provides nitrogen as the actuating medium for the reactor building to torus vacuum breaker butterfly valves when control air is not available
* provides nitrogen makeup to the MSRVs
* provides for heat transfer
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.2.7, the applicant identified the following CAD system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, flex hose, heat
 
exchangers, piping, tanks, tubing, and valves.
2.3.2.7.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.7, LRA Appendix F, and UFSAR Sections 5.2.3 and 5.2.6 using the evaluation methodology described in SER Section 2.3. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.3.
In conducting the review, the staff reviewed the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2-59 On the basis of its review, the staff found that the applicant identified those portions of the CAD system that meet the scoping requirements of 10 CFR 54.4 and included them within the scope
 
of license renewal in LRA Section 2.3.2.7. The applicant also included CAD system components
 
that are subject to an AMR in accordance with 10 CFR 54.4(a) and 10 CFR 54.21(a)(1) in LRA
 
Table 2.3.2.7, "Containment Atmosphere Dilution System," and in LRA Table 3.2.2.7, "Containment Atmosphere Dilution System-Su mmary of Aging Management Evaluation." LRA Section F.2, "Containment Atmosphere Dilution Sy stem Modifications," indicates that Unit 1 capability to supply pressurized nitrogen to operate the MSRVs when control air is not available
 
will be identical to the capability of Units 2 and 3 and will result in the same AMPs for each unit.
 
This item will be discussed in SER Section 2.6.1.2.
2.3.2.7.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In
 
addition, the staff performed a review to determine whether any components that should be
 
subject to an AMR had not been identified by the applicant. No omissions were identified. On
 
the basis of its review, the staff concluded that there is reasonable assurance that the applicant
 
had adequately identified the CAD system components that are within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and t he CAD system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3  Auxiliary Systems In LRA Section 2.3.3, the applicant identified the systems and components of the auxiliary systems that are subject to an AMR for license renewal in the following sections of the LRA:
* 2.3.3.1auxiliary boiler system
* 2.3.3.2fuel oil system
* 2.3.3.3residual heat removal service water system
* 2.3.3.4raw cooling water system
* 2.3.3.5raw service water system
* 2.3.3.6high pressure fire protection system
* 2.3.3.7potable water system
* 2.3.3.8ventilation system
* 2.3.3.9heating, ventilation, and air conditioning system
* 2.3.3.10control air system
* 2.3.3.11service air system
* 2.3.3.12CO 2 system
* 2.3.3.13station drainage system
* 2.3.3.14sampling and water quality system
* 2.3.3.15building heat system
* 2.3.3.16raw water chemical treatment system
* 2.3.3.17demineralizer backwash air system
* 2.3.3.18standby liquid control system
* 2.3.3.19off-gas system
* 2.3.3.20emergency equipment cooling water system
* 2.3.3.21RWCU system
* 2.3.3.22reactor building closed cooling water system 2-60
* 2.3.3.23reactor core isolation cooling system
* 2.3.3.24auxiliary decay heat removal system
* 2.3.3.25radioactive waste treatment system
* 2.3.3.26fuel pool cooling and cleanup system
* 2.3.3.27fuel handling and storage system
* 2.3.3.28diesel generator system
* 2.3.3.29control rod drive system
* 2.3.3.30diesel generator starting air system
* 2.3.3.31radiation monitoring system
* 2.3.3.32neutron monitoring system
* 2.3.3.33traversing in-core probe system
* 2.3.3.34cranes system The corresponding sub-sections of this SER (2.3.3.1 - 2.3.3.34) present the staff's review findings for each system of the auxiliary systems.
2.3.3.1  Auxiliary Boiler System 2.3.3.1.1  Summary of Technical Information in the Application In LRA Section 2.3.3.1, the applicant descri bed the auxiliary boiler sy stem. The auxiliary boiler system provides heating and miscellaneous steam services within the power house. This includes the ability to test the HPCI system and the RCIC system turbines while the reactor is
 
shutdown. This system is a plant-shared system.
The turbine building contains three oil-fired, auxiliary boilers.
The auxiliary boiler system contains SR com ponents that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the auxiliary boiler system could
 
prevent the satisfactory accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides primary and secondary containment boundaries
* establishes an MSIV pathway to the condenser
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.1, the applicant identifi ed the following auxiliary boiler system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, pipes, traps, tubing, and valves.
2.3.3.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.1 and UFSAR Sections 5.2, 5.3, and 10.20 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
2-61 In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER Section 2.1 related to NSR piping segments that support secondary containment, the applicant expanded the system boundaries for the auxiliary boiler system. By letter dated May 31, 2005, the applicant submitted the results of its review of piping, supports, and other components outside of the secondary containment required to maintain the structural integrity of the secondary containment that are within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2). In the enclosure to the letter the applicant stated that piping was added to scope. The component types do not differ from those listed in LRA Table 2.3.3.1;
 
therefore, no changes to the auxiliary boiler system portion of the LRA are required.
The staff reviewed the NSR piping segments and found the expanded scope of components to be acceptable, because the applicant had adequately included NSR components with the configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR piping or components.
2.3.3.1.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In
 
addition, the staff performed a review to determine whether any components that should be
 
subject to an AMR had not been identified by the applicant. No omissions were identified. On
 
the basis of its review, the staff concluded that there is reasonable assurance that the applicant
 
had adequately identified the auxiliary boiler system components that are within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and the auxiliary boiler system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.2  Fuel Oil System 2.3.3.2.1  Summary of Technical Information in the Application In LRA Section 2.3.3.2, the applicant described the fuel oil system. The fuel oil system is a plant-shared system; two large storage tanks are provided for the entire plant. Pumps transfer
 
fuel oil to the auxiliary boilers and storage tanks for the various diesel-driven engines. The
 
standby alternating current (AC) power fuel oil system consists of three interconnected storage tanks for each of the system's eight diesel generators (DGs). Transfer pumps are provided to transfer fuel from a 7-day storage tank to the associated DG day tank. These 7-day storage tanks can provide sufficient fuel for the operation of the DGs during seven continuous days, following a LOCA. The system is in standby dur ing normal operation and starts automatically, when required, to supply fuel to any operating DG. The other plant DGs each have a single
 
storage tank.
2-62 The fuel oil system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the fuel oil system could prevent the
 
satisfactory accomplishment of an SR function.
In addition, the fuel oil system performs functions that support fire protection and SBO.
The intended functions within the scope of license renewal include the following:
* provides diesel fuel oil to the DG system
* maintains a 7-day (long term) supply of fuel oil in storage tanks to support the DGsystem
* provides debris protection
* restricts flow
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.2, the applicant identified the following fuel oil system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, flex hose, piping, pumps, restricting orifice, stainers, tanks, tubing, and valves.
2.3.3.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.2 and UFSAR Section 8.5.3.4 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.2, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued RAIs concerning the
 
specific issues to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAIs and the applicant's related responses.
In RAI 2.3.3.2-1. the staff identified that components in the DG low level radioactive waste (LLRW) fuel oil subsystem and the diesel-driven fire pump LLRW fuel oil subsystem had not
 
been included in the LRA as being within the scope of license renewal and subject to an AMR.
 
The UFSAR does not describe either of these two subsystems. The staff is unable to determine
 
if these subsystems have intended functions that would satisfy any of the criteria in 2-63 10 CFR 54.4(a). Therefore, the staff requested that the applicant provide the design functions and associated licensing bases of these portions of the fuel oil system to determine if they can
 
be excluded from the scope of license renewal.
In its response, by letter dated October 19, 2004, the applicant stated that the two LLRW fuel oil subsystems provide fuel oil to the diesels to drive pumps that supply backup water to the
 
ancillary facilities fire protection system. The ar eas protected by the ancillary facilities fire protection system are outside the protected area of the plant and are not required for plant
 
shutdown.
Based on its review, the staff found the applicant's response to RAI 2.3.3.2-1 acceptable. The intended functions of these subsystems as described in the applicant's response are outside the
 
scope of license renewal in accordance with the requirements of 10 CFR 54.4(a). Therefore, the
 
staff's concern described in RAI 2.3.3.2-1 is resolved.
In RAI 2.3.3.2-2, the staff identified that a drain valve and associated piping and fittings on the diesel fuel tank for the diesel-driven fire pump had not been included in the LRA as being within
 
the scope of license renewal and subject to an AMR. Failure of this piping could affect the
 
upstream valve and drain the storage tank. Therefore, the staff requested that the applicant
 
justify the exclusion of the drain valve and associated piping and fittings from the scope of
 
license renewal.
In its response, by letter dated October 19, 2004, the applicant stated that none of the piping shown on the license renewal drawing is SR or seismically qualified; the piping is within the
 
scope of license renewal for fire protection. Failure of the short section of piping and fittings
 
downstream of normally closed valve, 0-DRV-703, would not cause the storage tank to drain.
Based on its review, the staff found the applicant's response to RAI 2.3.3.2-2 acceptable. There is a normally closed valve within the scope of license renewal upstream of the drain valve in
 
question; thus, failure of the short section of piping and fittings downstream of this valve would
 
not affect the intended function of the storage tank. Therefore, the staff's concern described in
 
RAI 2.3.3.2-2 is resolved.
2.3.3.2.3  Conclusion
 
The staff reviewed the LRA and RAI responses described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the
 
applicant. No omissions were identified. In addition, the staff performed a review to determine
 
whether any components that should be subject to an AMR had not been identified by the
 
applicant. No omissions were identified. On the basis of its review, the staff concluded that there
 
is reasonable assurance that the applicant had adequately identified the fuel oil system
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the fuel oil system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-64 2.3.3.3  Residual Heat Removal Service Water System 2.3.3.3.1  Summary of Technical Information in the Application In LRA Section 2.3.3.3, the applicant described the RHRSW system. The RHRSW system is a plant-shared system. The system pumps water di rectly from Wheeler Reservoir through the RHR heat exchangers and EECW system components and discharges the water back into the
 
Wheeler Reservoir.
The RHRSW system contains SR components that are relied upon to remain functional during, and following DBEs. The failure of NSR SSCs in the RHRSW could prevent the satisfactory
 
accomplishment of an SR function. In addition, the RHRSW performs functions that support fire
 
protection, EQ, and SBO.
The intended functions within the scope of license renewal include the following:
* provides cooling water to the RHR system heat exchangers
* provides cooling water to the EECW system upon start of the RHRSW pumps, given EECW valve position interlock signals
* provides a secondary containment boundary
* provides sump pump capability for RHRSW pump compartments
* provides debris protection
* restricts flow
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.3, the applicant identified the following RHRSW system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, piping, pumps, restricting orifice, strainers, tubing, and valves.
2.3.3.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.3 and UFSAR Sections 4.8, 5.3, 7.12.4, 7.18, 10.9, 10.10, 11.6, F.7.7, F.7.15, and F.7.16 using the evaluation methodology described in SER Section 2.3.
 
The staff conducted its review in accordance with the guidance described in SRP-LR
 
Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not 2-65 omitted any passive and long-lived components that should be subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.3, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning
 
the specific issue to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAI and the applicant's response.
In RAI 2.3.3.3-1, the staff stated that license renewal drawing 0-47E851-4-LR provides the drainage flow diagram (identified as system number 40 in the drawing title block). Most of the piping and valves for system 40 on the drawing are identified with UNIDs; however, the piping
 
on this drawing is shown in red, but does not identify UNIDs for the piping or pumps. Therefore, the staff requested the applicant to identify which components on this drawing are part of the
 
RHRSW system.
In its response, by letter dated October 19, 2004, the applicant stated that the piping and pumps shown in red on drawing 0-47E851-4-LR are associated with the pumping station and are part
 
of the RHRSW system (system 23). The pumps are tagged as RHRSW system 23 components and there are no UNIDs assigned to pipe. These components are part of the RHRSW and are
 
contained in LRA Table 2.3.3.3.
Based on its review, the staff found the applicant's response to RAI 2.3.3.3-1 acceptable. It confirms that the piping and pumps shown in red on the license renewal drawing are part of the
 
residual heat removal service water system and that the components in question are
 
appropriately included in LRA Table 2.3.3.3. Therefore, the staff's concern described in
 
RAI 2.3.3.3-1 is resolved.
2.3.3.3.3  Conclusion
 
The staff reviewed the LRA, the accompanying scoping boundary drawing, and RAI response described above to determine whether any SSCs that should be within the scope of license
 
renewal had not been identified by the applicant. No omissions were identified. In addition, the
 
staff performed a review to determine whether any components that should be subject to an
 
AMR had not been identified by the applicant. No omissions were identified. On the basis of its
 
review, the staff concluded that there is reasonable assurance that the applicant had adequately
 
identified the RHRSW system components that are within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and the RHRSW syst em components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.4  Raw Cooling Water System 2.3.3.4.1  Summary of Technical Information in the Application In LRA Section 2.3.3.4, the applicant described the raw cooling water (RCW) system. The RCW system cools plant components (including components in the reactor building) during normal
 
operations. The Unit 1 and Unit 2 RCW systems share pump suction and discharge headers
 
and seven RCW pumps. The separate, Unit 3 RCW system has five pumps that have a 2-66 separate suction header, but share a common discharge header with Units 1 and 2. Three pumps per unit are normally required. The RCW sy stem has interfaces with the EECW system, which is normally inservice. The RCW pumps are located in the turbine building and are
 
supplied from the condenser circulating water system.
The RCW system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the RCW system could prevent the satisfactory
 
accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides a secondary containment boundary
* provides pressure boundary integrity for the EECW system
* provides a flow path through control room chillers A and B for Units 1 and 2 only
* restricts flow
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.4, the applicant identified the following RCW system component types that are within the scope of license renewal and subject to an AMR: bolting, expansion joint, fittings, flex hose, piping, pumps, strainers, tubing and valves.
2.3.3.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.4 and UFSAR Sections 5.3, 10.7, and F.6.5 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.4, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning
 
the specific issue to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAI and the applicant's response.
In RAI 2.3.3.4-1, the staff identified that water chillers 1A and 1B on license renewal drawing 1-47E844-2-LR are not subject to an AMR, and heat exchangers are not listed as a component
 
type in LRA Table 2.3.3.4. The shell of the chillers serves as the pressure boundary and
 
structural support for the attached raw cooling water piping which is subject to an AMR.
2-67 Therefore, the staff requested that the applicant justify the exclusion of these chillers from being subject to an AMR.
In its response, by letter dated October 19, 2004, the applicant stated that the piping on the shell side of water chillers 1A and 1B had been removed to show these chillers abandoned in
 
place on drawing 1-47E844-1-LR. Since the raw water piping has been removed, the chillers no
 
longer perform a pressure boundary or structural support function. The applicant further stated
 
that the drawing has been revised and will be sent to the staff as part of the annual update.
Based on its review, the staff found the applicant's response to RAI 2.3.3.4-1 acceptable. Water chillers 1A and 1B no longer perform an intended function in accordance with the requirements
 
of 10 CFR 54.4(a) and are outside the scope of license renewal. Therefore, the staff's concern
 
described in RAI 2.3.3.4-1 is resolved.
In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER Section 2.1 related to NSR piping segments that support secondary containment, the applicant expanded the system boundaries for the raw coo ling water system. By letter dated May 31, 2005, the applicant submitted the results of its review of piping, supports, and other components outside of the secondary containment required to maintain the structural integrity of the secondary containment that are within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2). In the enclosure to the letter the applicant stated that piping was added to scope. The component types do not differ from those listed in LRA Table 2.3.3.4;
 
therefore, no changes to the raw cooling water system portion of the LRA are required.
The staff reviewed the NSR piping segments and found the expanded scope of components to be acceptable, because the applicant had adequately included NSR components with the configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR piping or components.
2.3.3.4.3  Conclusion
 
The staff reviewed the LRA and RAI responses described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the
 
applicant. No omissions were identified. In addition, the staff performed a review to determine
 
whether any components that should be subject to an AMR had not been identified by the
 
applicant. No omissions were identified. On the basis of its review, the staff concluded that there
 
is reasonable assurance that the applicant had adequately identified the RCW system
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the RCW system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.5  Raw Service Water System 2.3.3.5.1  Summary of Technical Information in the Application In LRA Section 2.3.3.5, the applicant described the raw service water (RSW) system. The RSW system furnishes water for yard-watering and the cooling of miscellaneous plant equipment that
 
requires only small quantities of cooling water. The system also functions as a 'keep-fill' system
 
for the fire protection system. The RSW system is supplied from river water from the condenser circulating water inlet conduit, through a strainer, and to the main RCW pump suction header for 2-68 each unit. Units 1 and 2 each have one RSW pump; Unit 3 has two RSW pumps. Therefore, four pumps supply the common plant system. Two 10,000-gallon storage tanks are located on
 
top of the reactor building. These tanks pressurize the high pressure fire protection (HPFP)
 
system header.
The RSW system contains SR components that are relied upon to remain functional during, and following, DBEs. In addition, the RSW system performs functions that support fire protection.
The intended functions within the scope of license renewal include the following:
* provides a secondary containment boundary
* provides a keep-fill system for the fire protection system
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.5, the applicant identified the following RSW system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, piping, tanks, tubing, and valves.
2.3.3.5.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.5 and UFSAR Sections 5.3, 10.8, 10.10, and F.6.6 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.5, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning
 
the specific issue to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAI and the applicant's related response.
In RAI 2.3.3.5-1, the staff identified that the raw service water components upstream of valve 1-25-703 are not included in the LRA as being within the scope of license renewal and subject
 
to an AMR. Similar arrangements exist for Units 2 and 3. This normally open, hand-operated
 
valve is located at the interface between the discharge of RSW pump 1A and the fire service
 
system. Therefore, the staff requested that the applicant provide the basis for using a normally
 
open, hand-operated valve as a pressure boundary from the upstream RSW system piping and components. The staff also requested that the applicant justify the exclusion of these
 
components from the scope of license renewal.
2-69 In its response, by letter dated October 19, 2004, the applicant stated that the fire protection capability to control and extinguish fires is not dependent on the operability of the raw service
 
water pumps. Therefore, these pumps are not in scope, and any piping and valves associated
 
with the RSW system are also not included within the scope of license renewal. Additionally, the
 
applicant stated that valve 1-25-703 is the first isolation valve off the 12-inch fire protection
 
headers tie-in to the RSW pumps, and is within the scope of license renewal as it provides an
 
isolable point between the RSW and fire protection systems.
Based on its review, the staff found the applicant's response to RAI 2.3.3.5-1 acceptable. The RSW pumps and associated components do not perform an intended function in accordance
 
with the requirements of 10 CFR 54.4(a), and are, therefore, outside the scope of license
 
renewal. Therefore, the staff's concern described in RAI 2.3.3.5-1 is resolved.
2.3.3.5.3  Conclusion
 
The staff reviewed the LRA and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the RSW system
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the RSW system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.6  High Pressure Fire Protection System 2.3.3.6.1  Summary of Technical Information in the Application In LRA Section 2.3.3.6, the applicant descri bed the HPFP system. The HPFP system supplies water for fixed water spray, pre-action sprinkler, and aqueous foam systems for selected
 
equipment and areas in the control building, reactor buildings, turbine building, intake pumping
 
station, hydrogen trailer port, transformer yard, DG buildings, and service buildings.
The HPFP system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the HPFP system could prevent the
 
satisfactory accomplishment of an SR function.
In addition, the HPFP system performs functions that support fire protection.
The intended functions within the scope of license renewal include the following:
* supports a secondary containment function
* provides automatic fire protection for known hazardous areas where it is practical
* provides adequate warning of a fire in hazardous areas where automatic protection is not feasible to provide adequate manually-actuat ed fire protection systems for the entire plant and yard areas (i.e., hose stations, hydrants, etc.)
* ensures the maintenance of divisional integrity of SR systems to the extent that the capability for safe shutdown of the reactors is assured during and after a fire 2-70
* provides debris protection
* provides mechanical closure
* provides pressure boundary
* provides spray pattern
* provides structural support In LRA Table 2.3.3.6, the applicant identified the following HPFP system component types that are within the scope of license renewal and subject to an AMR: bolting, fan housing, fire
 
hydrants, fire hose stations, fittings, flexible connectors, heaters, heat exchangers, piping, pumps, restricting orifice, silencer, sprinkler heads, strainers, tanks, tubing, and valves.
2.3.3.6.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.6 and UFSAR Sections 10.11 and F.6.9 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). In addition, the staff also reviewed the BFN Fire Protection
 
Report (FPR) (Volumes 1 and 2). This report is referenced directly in the BFN fire protection
 
CLB and summarizes the fire protection program and commitments to 10 CFR 50.48 using the
 
guidance of Appendix A to Branch Technical Position (BTP) Auxiliary and Power Conversion
 
Systems Branch (APCSB) 9.5-1. The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.6, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 23, 2004, the staff issued RAIs concerning the
 
specific issues to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAIs and the applicant's related responses and staff evaluation.
In RAI 2.3.3.6-1, the staff stated that the sy stem description of the HPFP system in LRA Section 2.3.3.6 includes fixed water spray system
: s. Such systems typically utilize water spray nozzles. The staff identified that LRA Table 2.3.3.6 does not include water spray nozzles as a
 
component subject to an AMR. Therefore, the staff requested that the applicant indicate
 
whether the fixed water spray systems use spray nozzles other than the sprinkler heads. If so, staff stated that the nozzles, which are intended to support the system function, are passive and
 
long-lived and should be subject to an AMR.
In its response, by letter dated September 30, 2004, the applicant stated that fire protection spray nozzles (including spray nozzles attached to fire hoses) had been included in component
 
type "sprinkler heads" in LRA Table 2.3.3.6.
2-71 Based on its review, the staff found the applicant's response to RAI 2.3.3.6-1 acceptable. The components in question are included in scope and are subject to an AMR. Therefore, the staff's
 
concern described in RAI 2.3.3.6-1 is resolved.
In RAI 2.3.3.6-2, the staff stated that the sy stem description of the HPFP system in LRA Section 2.3.3.6 describes detection and alarm devices that automatically initiate the system or prompt manual fire fighting. The staff stated that these devices are not identified on the license
 
renewal drawings, nor are they discussed in t he fire protection program. Therefore, the staff requested that the applicant explain what these devices are and whether they are subject to an AMR.In its response, by letter dated September 30, 2004, the applicant stated that the alarm and detection devices do not perform a pressure boundary function, are active components, and are
 
evaluated as electrical commodities.
Based on its review, the staff found the applicant's response to RAI 2.3.3.6-2 acceptable. The components in question are electrical, not mechanical, and are active, and therefore are not
 
subject to an AMR. Therefore, the staff's concern described in RAI 2.3.3.6-2 is resolved.
In RAI 2.3.3.6-3, the staff stated that the LRA shows that the boundary of the HPFP system is the service building wall. The staff stated that the boundary shown is not at an isolated pressure
 
boundary (e.g., a valve or blank flange). Therefore, the staff requested that the applicant justify
 
the exclusion of the service building portions of the system from the scope of license renewal.
In its response, by letter dated September 30, 2004, the applicant stated that the boundary does not end at the service building wall but continues on license renewal drawing 1-47E850-2-LR.
 
BFN drawings depict continuation to other drawings with drawing coordinate flags. For
 
clarification, the reference to drawing coordinate flag 1-47E850-2 G6 should have been colored
 
red on license renewal drawing 1-47E850-1-LR. The boundary should end at the isolation valve
 
0-26-907 on drawing 1-47E850-2-LR. The boundary extends to an appropriate isolation valve.
Based on its review, the staff found the applicant's response to RAI 2.3.3.6-3 acceptable. The boundary extends to an appropriate isolation valve. Therefore, the staff's concern described in
 
RAI 2.3.3.6-3 is resolved.
In RAI 2.3.3.6-4, the staff stated that the LRA identifies a water curtain around the equipment hatch at elevation 565 feet. Table 9.3.11.B in Volume 1 of the FPR lists water curtains for the
 
RHR pump room equipment hatches at elevation 541 feet. The staff identified that the license
 
renewal drawings do not show anything on elevation 541 feet. Therefore, the staff requested
 
that the applicant clarify that the water curtain protection for the RHR pump room equipment
 
hatches are within the scope of license renewal, and identify where they are located on the
 
license renewal drawings.
In its response, by letter, dated September 30, 2004, the applicant stated that the water curtains at BFN are typically provided to protect floor openings and include closely spaced sprinklers
 
and draft stops located around the opening underneath the floor slab. In Unit 3 reactor building
 
elevation 565 feet, as shown on license renewal drawing 3-47E850-5, water curtains are
 
provided at the following six different locations:
2-72  (1)equipment hatch in floor opening above (between floor elevation 565 feet and 593 feet)    (2)stair #22 floor opening above (between floor elevation 565 feet and 593 feet)
  (3)east RHRSW heat exchanger (HX) room portal (door opening)
  (4)west RHRSW HX room portal (door opening)
  (5)east RHRSW HX room floor opening below (between elevation 541 feet and 565 feet)
  (6)west RHRSW HX room floor opening below (between elevation 541 feet and 565 feet)The water curtains (5 and 6) in the RHRSW HX room floor opening are located below elevation 565 feet floor slab to protect the opening from the fire effects of elevation 541 feet. These two
 
water curtains are the ones described in Table 9.3.11.B, Volume 1 of the FPR as the water
 
curtains for the RHR pump room equipment hatches at elevation 541 feet. These water curtains
 
are within the scope of license renewal.
Based on its review, the staff found the applicant's response to RAI 2.3.3.6-4 acceptable. The water curtains in question were verified by the applicant to be within the scope of license
 
renewal. Therefore, the staff's concern described in RAI 2.3.3.6-4 is resolved.
In reviewing the FPR, the staff identified the need for additional information related to the fire water supply systems and fire protection coating. In a letter dated August 23, 2004, the staff
 
asked the applicant to clarify information contained in the FPR Volume 1, Sections 4.4.1.A and
 
4.4.5. The following paragraphs describe the staff's RAIs and the applicant's related responses.
 
In RAI 4.4.1-1, the staff stated that FPR Section 4.4.1.A addresses a separate water supply
 
system, including tank and pumps, which does not appear in the LRA or boundary drawings. In
 
RAI 4.4.1-1, the staff requested the applicant to verify whether these system components are within the scope of license renewal and provide the justification if they are not.
In its response, by letter dated September 30, 2004, the applicant stated that the separate water supply ID referring to the outside loop is not within the scope of license renewal, since it is
 
servicing NSR areas of the plant that prov ide equipment/property protection and meet the Nuclear Electric Insurance Limited (NEIL) require ments. Therefore, they do not meet any criteria of 10 CFR 54.4.
Based on it review, the staff found the applicant's response to RAI 4.4.1-1 acceptable. Even though the separate water supply can be connected to the HPFP system as a backup identified
 
in plant procedures, it is not connected by fixed piping and valves. Therefore, the staff
 
concurred that the separate water supply is not within the scope of license renewal, and the
 
staff concern described in RAI 4.4.1-1 is resolved.
In RAI 4.4.5-1, the staff stated that FPR Section 4.4.5 states that "Flamemastic" was applied to cables that did not meet Institute of Electrical and Electronics Engineers (IEEE)-383 flame test
 
requirements. Inspection Testing and Maintenance of this is not referenced in the FPR. No
 
reference is made to it in the LRA, either under the Fire Protection Program, LRA
 
Section B.2.1.23, or in the electrical or structural programs. Therefore, the staff requested that
 
the applicant supply the AMR and AMP that are applicable to the Flamemastic coating. The staff 2-73 also asked the applicant to include program documents and procedures credited for managing the loss of material for Flamemastic coating.
In its response, by letter dated September 30, 2004, the applicant stated that Flamemastic is primarily used as a flame retardant on non-IEEE-383 qualified cables. This commitment
 
originated as part of the post-Fire Recovery Plan. As stated in the FPR, current practice is to
 
use cables that meet the IEEE-383 requirements for flame retardant and, therefore, Flamemastic is not applied to these cables. Since Flamemastic is not considered a fire stop or a
 
fire-resistive barrier, the 10 CFR Part 50, Appendix R, safe-shutdown analysis does not take
 
credit for it. Some cable tray penetration seal assemblies, however, use a coating of
 
Flamemastic on the fiber board and cables around the opening to meet the fire barrier function.
 
Materials listed in LRA Sections 3.5.2.1.2 and 3.5.2.1.5 should include Flamemastic coatings, when used in a qualified fire barrier configuration, to include both sides of the reactor
 
building/turbine building wall cable tray penetrations.
By letter dated January 25, 2005, applicant stated that the aging effects requiring management were incorrectly assigned to Flamemastic when used in the qualified fire barrier configuration.
 
At BFN, fire barrier penetration seal materials and Flamemastic coatings on exposed cables in
 
open trays are exposed to an inside air environm ent and, therefore, have no aging effects and require no AMP.
The applicant further stated that, based on the above discussion, aging effects were also incorrectly assigned to fire barrier materials Thermolag, Elastomers, and Gypsum. LRA
 
Section 3.5 will be revised to update the aging effects requiring management for these fire
 
barrier materials.
Based on review of the applicant's response, as supplemented by letter dated January 25, 2005, the staff concurred that the proposed modifications to the LRA are appropriate, because
 
Flamemastic coating on exposed cable trays are exposed to an inside air environment and require no AMR and AMP but are included within the scope of license renewal. Therefore, the
 
staff's concern described in RAI 4.4.5-1 is resolved.
In addition, the staff, during its audit review held during the week of July 21 - 25, 2004, discussed the following issue for the Fire Protection Program.
In its letter, dated October 28, 2004, the applicant stated that Procedure FP-0-041-INS008, Process Computer Room Halon 1301 System Functional Test, identifies a Halon 1301 total
 
flooding system on elevation 539 feet of the Control Bay (room 594.0-C1). No reference to
 
Halon systems appears in the LRA (scoping, screening, AMR or AMP.) The applicant was
 
requested to justify the exclusion of this system from license renewal.
The applicant also stated in its response that the Halon system does not provide fire protection for any equipment for plant shutdown but is inst alled to provide equipment/property protection and meet NEIL requirements. Therefore, this sy stem does not meet any of the criteria of 10 CFR 54.4. Based upon its review, the staff agreed that the Halon 1301 systems identified in
 
FP-0-041-INS008 are not part of the plant licensing basis and, therefore, are not within the
 
scope of license renewal. The staff concern described above is resolved.
2-74 2.3.3.6.3  Conclusion The staff reviewed the LRA and RAI responses described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the
 
applicant. No omissions were identified. In addition, the staff performed a review to determine
 
whether any components that should be subject to an AMR had not been identified by the
 
applicant. No omissions were identified. On the basis of its review, the staff concluded that there
 
is reasonable assurance that the applicant had adequately identified the HPFP system
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the HPFP system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.7  Potable Water System 2.3.3.7.1  Summary of Technical Information in the Application In LRA Section 2.3.3.7, the applicant described the potable water system. The potable water system supplies potable water for use in the pl umbing systems and is supplied by the city of Athens, AL. Potable water is supplied to various areas in the plant. Backflow preventers are
 
installed at each interface between the potable water system and the separate connecting
 
systems, in order to protect the potable water supply from possible contamination due to
 
backflow. The potable water system is a plant-shared system.
The potable water system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the potable water system could
 
prevent the satisfactory accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides a secondary containment boundary
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.7, the applicant identified the following potable water system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, piping, tubing, and valves.
2.3.3.7.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.7 and UFSAR Sections 5.3, 10.15, and F.6.11 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not 2-75 omitted any passive and long-lived components that should be subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER Section 2.1 related to NSR piping segments that support secondary containment, the applicant
 
expanded the system boundaries for the potable water system.
By letter dated May 31, 2005, the applicant submitted the results of its review of piping, supports, and other components outside of the secondary containment required to maintain the structural integrity of the secondary containment that are within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2). In the enclosure to the letter the applicant stated that new
 
component types, valves and tanks, were added to the scope as referenced in new LRA
 
Tables 2.3.3.7 and 3.3.2.7.
The staff reviewed the NSR piping segments and found the expanded scope of components to be acceptable, because the applicant had adequately included NSR components with the configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR piping or components.
2.3.3.7.3  Conclusion
 
The staff reviewed the LRA and RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff performed a review to determine whether any components that
 
should be subject to an AMR had not been identified by the applicant. No omissions were
 
identified. On the basis of its review, the staff concluded that there is reasonable assurance that
 
the applicant had adequately identified the potable water system components that are within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and the potable water system
 
components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.8  Ventilation System 2.3.3.8.1  Summary of Technical Information in the Application In LRA Section 2.3.3.8, the applicant descri bed the ventilation system. The ventilation system contains subsystems that provide ventilation and heating for various plant buildings, including
 
the radioactive waste building and the DG buildings. The ventilation system does not include the
 
HVAC systems or the reactor building ventilation systems.
These systems are discussed in SER Section 2.3.3.9. The ventilation system is a plant-shared system.
The radioactive waste building ventilation system consists of two 50-percent capacity supply fans that filter air to central areas on the various plant floor levels. The ventilation
 
systems for the DG buildings are designed to ma intain the required environmental conditions for SR equipment located in the Unit 1, 2, and 3 DG buildings.
The ventilation system contains SR components that are relied upon to remain functional during, and following, DBEs. In addition, the vent ilation system performs functions that support fire protection and SBO.
2-76 The intended functions within the scope of license renewal include the following:
* provides ventilation to the Unit 1, 2, and 3 DG buildings
* provides ventilation to the 250 volt (V) Battery Room 3EB in the Unit 3 DG building to prevent the buildup of hydrogen gas during battery charging
* provides for secondary containment integrity (passive)
* provides debris protection
* provides fire barrier
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.8, the applicant identified the following ventilation system component types that are within the scope of license renewal and subject to an AMR: bolting, ductwork, fire
 
dampers, and fittings.
2.3.3.8.2  Staff Evaluation
 
The staff reviewed LRA Sections 2.3.3.8 and BFN Units 1, 2, and 3 UFSAR Sections 5.3 and 10.12, and F.7.11 using the evaluation methodology described in SER Section 2.3. The staff
 
conducted its review in accordance with the guidance described in SRP-LR Section 2.3.
In conducting the review, the staff reviewed the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.8, the staff identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. Therefore, by the letter dated October 8, 2004, the staff issued an RAI concerning the specific issues to
 
determine whether the applicant had properly applied the scoping criteria of 10 CFR 54.4(a) and
 
the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff's RAI
 
and the applicant's related responses.
In RAI 2.3.3.8-1, the staff requested that the applicant clarify whether all the system components such as, but not limited to, damper housings including fire damper housings, fan
 
housings, air intake and exhaust structures including screens, supply and exhaust grills, etc.,
are within the scope of license renewal in accordance with 10 CFR 54.4(a), and subject to an
 
AMR in accordance with 10 CFR 54.21(a)(1).
In its response, by letter dated November 3, 2004, and supplemented by a letter dated December 3, 2004, the applicant stated that (1) the damper housings and fan housings are 2-77 included in component type "ductwork" in LRA Table 2.3.3.8, (2) fire damper housings are included in component type "fire dampers" in LRA Table 2.3.3.8, (3) screens associated with the
 
exhaust plenum in the Units 1 & 2 DG building and the Unit 3 DG building are included in
 
component type "ductwork" in LRA Table 2.3.3.
8, and (4) intake/exhaust plenums associated with the DG buildings are considered part of the structure and are contained in LRA
 
Table 2.4.3.1 and LRA Table 3.5.2.5. LRA Section 2.3.5, "Notes Associated with the Section 2.3
 
Tables," "Component Types" are revised to reflect these components and, therefore, are part of
 
LRA Table 2.3.3.8, "ventilation system" and LRA Table 3.3.2.8, "Ventilation System-Summary of Aging Management Evaluation."
Based on its review, the staff found the applicant's response to RAI 2.3.3.8-1 acceptable. The applicant clarified that all applicable syst em components consisting of damper housings including fire damper housings, fan housings, air intake and exhaust structures including
 
screens and all other applicable components of the system are within the scope of license
 
renewal, and subject to an AMR for the vent ilation system. Supply and exhaust grills do not perform any SR function, therefore, are ex cluded from the scope of license renewal. Therefore, the staff's concern described in RAI 2.3.3.8-1 for those "Component Types" in LRA
 
Tables 2.3.3.8 and 3.3.2.8 is resolved.
2.3.3.8.3  Conclusion
 
The staff reviewed the LRA and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the ventilation system
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the ventilation system components that ar e subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.9  Heating, Ventilation, and Air Conditioning System 2.3.3.9.1  Summary of Technical Information in the Application In LRA Section 2.3.3.9, the applicant described the HVAC system. The HVAC subsystems provide air-conditioned ventilation for various plant areas. The various HVAC subsystems provide environmental control, ventilation, and cooling. Ventilation and cooling is provided so that the temperatures of the control bay and s hutdown electrical board rooms (including those in the Unit 3 DG building) are maintained within acceptable limits for the operation of instruments
 
and other equipment during accidents and events. Ventilation is also provided to the battery
 
room to prevent the buildup of explosive gases.
In addition, the HVAC subsystems provide for the cooling of various electrical equipment rooms (e.g., computer and communications rooms) so that their temperatures are maintained within acceptable limits for the operation of
 
instruments and other equipment.
The HVAC system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the HVAC system could prevent the 2-78 satisfactory accomplishment of an SR functi on. In addition, the HVAC system performs functions that support fire protection, EQ, and SBO.
The intended functions within the scope of license renewal include the following:
* isolates supply ducts and supplies pressurized filtered outdoor air to main control room on primary containment isolation system gr oup six signal or radiation monitoring system initiation signal
* provides ventilation to cable spr eading rooms and control bay mechanical equipment rooms
* recirculates cool air to the reactor building board rooms
* provides ventilation and air conditioning to the board rooms of the Unit 3 DG buildings and ventilation to the battery rooms
* provides recirculation air conditioning to control rooms and auxiliary instrument rooms
* provides manual lineup of HVAC equipment with total loss of control air
* provides a secondary containment boundary
* provides debris protection
* provides fire barrier
* provides for heat transfer
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.9, the applicant identified the following HVAC system component types that are within the scope of license renewal and subject to an AMR: bolting, ductwork, fire dampers, fittings, flexible connectors, heat exchangers, heaters, piping, pumps, refrigerant compressor, strainers, tanks, tubing, and valves.
2.3.3.9.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.9 and UFSAR Sections 10.12 and F.7.11 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
In conducting the review, the staff reviewed the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2-79 In reviewing LRA Section 2.3.3.9, the staff identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. Therefore, by the letter dated October 8, 2004, the staff issued an RAI concerning the specific issues to
 
determine whether the applicant had properly applied the scoping criteria of 10 CFR 54.4(a) and
 
the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff's RAI
 
and the applicant's related responses.
In RAI 2.3.3.9-1, the staff requested that the applicant clarify whether all the system components such as, but not limited to, fan housings, filter housings, cooling coil housings, damper housings including fire damper housings, metal lath screens, valve bodies, supply and
 
return grills, and all other applicable components of the system, including duct sealants, wall
 
sealants, pressure boundary sealants, screens for intake and exhaust structures, etc., are within
 
the scope of license renewal in accordance with 10 CFR 54.4(a), and subject to an AMR in
 
accordance with 10 CFR 54.21(a)(1).
In its response, by letter dated November 3, 2004, and supplemented by a letter dated December 3, 2004, the applicant stated the following:
* Fan housings, filter housings, cooling coil housings, and damper housings are included in component type "ductwork" in LRA Table 2.3.3.9.
* Metal lath screens shown on drawings 0-47E865-8-LR and 3-47E865-8-LR are included in component type "ductwork" in LRA Table 2.3.3.8.
* Screens and plenums will be included in the component type "ductwork."
* LRA Table 3.3.2.9 will be revised to include "outside air (external)" for "ductwork." A new row will be added for stainless steel "bolting" category with an outside air environment.
* Valve bodies are included in component type "valves" in LRA Table 2.3.3.9.
* Structural sealants such as those required to maintain the control room envelope or secondary containment are contained in Section 3.5.2.1.2 and in component type
 
"compression joints and seals" and in component type "caulking and sealants" in LRA
 
Table 3.5.2.2,
* Pressure boundary sealants associated with ductwork for HVAC system are included in component type "ductwork" in LRA Tables 2.3.3.9 and 3.3.2.9, and screens and plenums
 
are included in the component type "ductwork."
The supply and return grilles have no 10 CFR 54.4(a)1, 10 CFR 54.4(a)2, or 10 CFR 54.4(a)3 functions for license renewal and are not included in the LRA Tables. LRA Section 2.3.5, "Notes
 
Associated with the LRA Section 2.3 tables," "Component Types" is revised to reflect these
 
components and, therefore, is part of LRA Table 2.3.3.9, "Heating, Ventilation, and Air
 
Conditioning System," and LRA Table 3.3.2.9, "Heating, Ventilation, and Air Conditioning
 
System-Summary of Aging Management Evaluation."
Based on its review, the staff found the applicant's response to RAI 2.3.3.9-1 acceptable. The applicant clarified that all applicable system components consisting of fan housings, filter
 
housings, cooling coil housings, damper housings, metal lath screens, screens and plenums, valve bodies, structural sealants to maintain the control room envelope including compression
 
joints and seals, and pressure boundary sealants associated with ductwork are within the scope 2-80 of license renewal, and subject to an AMR for the HVACS and are already included in "Component Types" in LRA Tables 2.3.3.9 and 3.3.2.9. Therefore, the staff's concern described
 
in RAI 2.3.3.9-1 is resolved.
2.3.3.9.3  Conclusion
 
The staff reviewed the LRA and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the HVAC system
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the HVAC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.10  Control Air System 2.3.3.10.1  Summary of Technical Information in the Application In LRA Section 2.3.3.10, the applicant described the control air system. The control air system provides motive power for numerous plant components during normal operations and
 
post-accident motive power to the torus vac uum breaker valves. The system also provides post-accident motive power to the MS isolation valves and the main steam safety relief valves (MSRVs) for reactor vessel overpressure relief protection and reactor vessel depressurization, including the ECCS automatic depressurization function.
The control air system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the control air system could prevent the
 
satisfactory accomplishment of an SR function.
In addition, the control air system performs functions that support fire protection, EQ, and SBO.
The intended functions within the scope of license renewal include the following:
* performs isolation action(s) upon receivi ng primary containment system (64D) group six isolation signals
* provides compressed air to the MS sy stem atmospheric dilution system (ADS) safety relief valves
* provides compressed air for closure of the MSIVs
* provide primary containment boundary
* provides compressed air to equipment access air lock seals to provide a secondary containment boundary
* provides and supports the secondary containment boundary
* provides for flow path integrity for supply of CAD nitrogen to the torus vacuum breaker valves
* provides a flow path for the CAD system to provide nitrogen to MSRVs 2-81
* provides for flow distribution
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.10, the applicant identified the following control air system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, flexible
 
connectors, heat exchangers, piping, restricting orifice, tanks, tubing, and valves.
2.3.3.10.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.10 and UFSAR Sections 5.2.3, 5.3, 10.14, and F.6.3 using the evaluation methodology described in SER Section 2.3. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.10.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In
 
addition, the staff performed a review to determine whether any components that should be
 
subject to an AMR had not been identified by the applicant. No omissions were identified. On
 
the basis of its review, the staff concluded that there is reasonable assurance that the applicant
 
had adequately identified the control air system components that are within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and the c ontrol air system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.11  Service Air System 2.3.3.11.1  Summary of Technical Information in the Application In LRA Section 2.3.3.11, the applicant described the service air system. The service air system is a plant-shared system and consists of two air compressors that are located in the turbine
 
building. The system's primary function is to provide pressurized air to hose connections
 
throughout the plant yard and to miscellaneous equipment in the standby liquid control (SLC)
 
system, Amertap condenser tube cleaning system (a subsystem of the condenser circulating water system), condensate demineralizer ai r surge system, and the radwaste system.
The service air system contains SR components that are relied upon to remain functional during, and following, DBEs.
2-82 The intended functions within the scope of license renewal include the following:
* provides primary and secondary containment boundaries
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.11, the applicant identified the following service air system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, piping, and valves.2.3.3.11.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.11 and UFSAR Sections 5.2.3, 5.3, 10.14, and F.6.3 using the evaluation methodology described in SER Section 2.3. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER Section 2.1 related to NSR piping segments that support secondary containment, the applicant expanded the system boundaries for the service ai r system. By letter dated May 31, 2005, the applicant submitted the results of its review of piping, supports, and other components outside of the secondary containment required to maintain the structural integrity of the secondary containment that are within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2). In the enclosure to the letter the applicant stated that piping, fittings, and valves were added to scope. The component types do not differ from those listed in LRA
 
Table 2.3.3.11; therefore, no changes to the service air system portion of the LRA are required.
The staff reviewed the NSR piping segments and found the expanded scope of components to be acceptable, because the applicant had adequately included NSR components with the configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR piping or components.
2.3.3.11.3  Conclusion
 
The staff reviewed the LRA and RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff performed a review to determine whether any components that
 
should be subject to an AMR had not been identified by the applicant. No omissions were
 
identified. On the basis of its review, the staff concluded that there is reasonable assurance that
 
the applicant had adequately identified the service air system components that are within the 2-83 scope of license renewal, as required by 10 CFR 54.4(a), and the service air system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.12  CO 2 System 2.3.3.12.1  Summary of Technical Information in the Application In LRA Section 2.3.3.12, the applicant described the CO 2 system. The CO 2 system is a fire suppression system for the DG buildings, turbine building, and control bay spaces that contain
 
electrical, lubricating oil, or fuel oil components. Units 1 and 2 share a system that includes a
 
17-ton storage tank. Unit 3 has a separate system with a 6-ton tank. The system is in standby
 
during normal operation and initiates automatically, as required. When initiated, ventilation
 
systems that could reduce the effectiveness of the CO 2 discharge are isolated. Detection and alarm devices that automatically initiate the sy stem, or would prompt manual fire firefighting activities, are also included in the CO 2 system. The CO 2 system performs functions that support fire protection.
The intended functions within the scope of license renewal include the following:
* provides CO 2 fire protection for oil and electrical hazards affecting the minimum safe shutdown system (SSDS) components requir ed to achieve safe shutdown capability
* provides fire barrier
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.12, the applicant identified the following CO 2 system component types that are within the scope of license renewal and subject to an AMR: bolting, ductwork, fire dampers, fittings, piping, rupture disk, tanks, tubing, and valves.
2.3.3.12.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.12 and UFSAR Sections 10.11 and F.6.9 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). In addition, the staff also reviewed BFN FPR volumes 1 and
: 2. This report is referenced directly in the fire protection CLB and summarizes the Fire
 
Protection Program and commitments to 10 CFR 50.48 using the guidance of Appendix A to
 
BTP APCSB 9.5-1. The staff then reviewed those components that the applicant had identified as being within the scope of license renewal to verify that the applicant had not omitted any
 
passive and long-lived components that should be subject to an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
2-84 In reviewing LRA Section 2.3.3.12, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 23, 2004, the staff issued RAIs concerning the
 
specific issues to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAIs and the applicant's related responses.
In RAI 2.3.3.12-1, the staff stated that the CO 2 system addressed in LRA Section 2.3.3.12 typically requires discharge nozzles to achieve the proper flow rate. The staff identified that the
 
system description and LRA Table 2.3.3.12 do not include any reference to discharge nozzles.
 
Therefore, the staff requested the applicant to indicate whether this system includes discharge
 
nozzles. If so, the staff stated that the nozzles, which perform an intended function for flow
 
control, are passive and long lived and should be subject to an AMR.
In its response, by letter dated September 30, 2004, the applicant stated that the discharge nozzles were included within component type "fittings" in Table 2.3.3.12 with an intended
 
function of pressure boundary and subject to an AMR.
Based on the response, the staff concurred that the nozzles are within the scope of license renewal and subject to an AMR, but disagreed that the intended function is pressure boundary.
 
The nozzles contain open orifices and serve a flow control function rather than a pressure
 
boundary. The staff reviewed plant procedures 0-SI-4.11.D.1.b, 1/2-SI-4.11.D.1.b, and
 
3-SI-4.11.D.1.b for CO 2 system functional testing and found the nozzles are adequately addressed in the fire protection AMP. Therefore, the staff concern described in RAI 2.3.3.12-1 is
 
resolved.In RAI 2.3.3.12-2, the staff stated that the system description of the CO 2 system in LRA Section 2.3.3.12 addresses detection and alarm devices that automatically initiate the system or prompt manual fire fighting. The staff stated that these devices are not identified on the license
 
renewal drawings, nor are they discussed in the Fire Protection Program. Therefore, the staff
 
requested that the applicant explain what these devices are and whether they are subject to an AMR.In its response, by letter dated September 30, 2004, the applicant stated that the CO 2 system fire protection detection and alarm devices do not form a pressure boundary and are active
 
components and evaluated as electrical commodities.
Based on its review, the staff found the applicant's response to RAI 2.3.3.12-2 acceptable. The components in question are electrical, not mechanical, and are therefore active and not subject
 
to an AMR. Therefore, the staff's concern described in RAI 2.3.3.12-2 is resolved.
2.3.3.12.3  Conclusion
 
The staff reviewed the LRA and RAI responses described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the
 
applicant. No omissions were identified. In addition, the staff performed a review to determine
 
whether any components that should be subject to an AMR had not been identified by the
 
applicant. No omissions were identified. On the basis of its review, the staff concluded that there
 
is reasonable assurance that the applicant had adequately identified the CO 2 system 2-85 components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CO 2 system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.13  Station Drainage System 2.3.3.13.1  Summary of Technical Information in the Application In LRA Section 2.3.3.13, the applicant described the station drainage system. The station drainage system is a plant-shared system that collects, processes, stores, and disposes of non-radioactive liquid waste. Portions of the piping within the system penetrate the secondary
 
containment.
The station drainage system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the station drainage system could
 
prevent the satisfactory accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides a secondary containment boundary
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.13, the applicant identified the following station drainage system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, piping, and valves.
2.3.3.13.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.13 and UFSAR Sections 5.3 and 10.16 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.13, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning
 
the specific issue to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAI and the applicant's related response.
2-86 In RAI 2.3.3.13-1, the staff identified a 3-inch roof drain (at roof elevation 667 feet on license renewal drawing 0-47E851-1-LR,) that is not within the scope of license renewal and subject to
 
an AMR. This drain provides a pressure boundary function between the standby gas treatment
 
system and the off-gas system; thus it should be within the scope of license renewal. The staff noted that a 4-inch roof drain on the same drawing is shown as being subject to an AMR.
 
Therefore, the staff requested that the applicant justify the exclusion of the 3-inch roof drain
 
from the scope of license renewal and from being subject to an AMR.
In its response, by letter dated October 19, 2004, the applicant stated that the 3-inch roof drain should have been colored in red on drawing 0-47E851-1-LR, since it is within the scope of
 
license renewal as part of the component type "fittings" in LRA Table 2.3.3.13 and subject to an
 
AMR. The applicant further stated that drawing 0-47E851-1-LR has been revised to show the
 
3-inch roof drain highlighted in red and will be resent as part of the annual update.
Based on its review, the staff found the applicant's response to RAI 2.3.3.13-1 acceptable. It concurs that the 3-inch roof drain should be within the scope of license renewal and the drain
 
included in LRA Table 2.3.3.13 as a component type subject to an AMR. Therefore, the staff's
 
concern described in RAI 2.3.3.13-1 is resolved.
In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER Section 2.1 related to NSR piping segments that support secondary containment, the applicant expanded the system boundaries for the station drainage system. By letter dated May 31, 2005, the applicant submitted the results of its review of piping, supports, and other components outside of the secondary containment required to maintain the structural integrity of the secondary containment that are within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2). In the enclosure to the letter the applicant stated that piping, fittings, and check valves were added to scope. The component types do not differ from those
 
listed in LRA Table 2.3.3.13; therefore, no changes to the station drainage system portion of the
 
LRA are required.
The staff reviewed the NSR piping segments and found the expanded scope of components to be acceptable, because the applicant had adequately included NSR components with the configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR piping or components.
2.3.3.13.3  Conclusion
 
The staff reviewed the LRA, the accompanying scoping boundary drawing, and RAI responses described above to determine whether any SSCs that should be within the scope of license
 
renewal had not been identified by the applicant. No omissions were identified. In addition, the
 
staff performed a review to determine whether any components that should be subject to an
 
AMR had not been identified by the applicant. No omissions were identified. On the basis of its
 
review, the staff concluded that there is reasonable assurance that the applicant had adequately
 
identified the station drainage system components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the station drainage system components that are subject to
 
an AMR, as required by 10 CFR 54.21(a)(1).
2-87 2.3.3.14  Sampling and Water Quality System 2.3.3.14.1  Summary of Technical Information in the Application In LRA Section 2.3.3.14, the applicant described the sampling and water quality system. The sampling and water quality system provides the capability to obtain representative samples for
 
testing. The data are used to evaluate the performance of the plant, equipment, and systems
 
during normal plant operations. Using a post-accident sample subsystem, representative
 
samples of reactor coolant, torus liquid, drywell atmosphere, torus atmosphere, and secondary
 
containment atmosphere can be obtained after a LOCA to guide post-LOCA actions regarding
 
Units 2 and 3. Portions of the system are credited in analyses for MSIV alternate leakage
 
treatment.
The sampling and water quality system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the sampling and water
 
quality system could prevent the satisfactory a ccomplishment of an SR function. In addition, the sampling and water quality system performs functions that support fire protection, EQ, and
 
SBO.The intended functions within the scope of license renewal include the following:
* provides RCPB
* provides primary and secondary containment boundaries
* maintains residual heat removal service water system pressure boundary integrity
* provides a pressure boundary of the sampling and water quality system components connected to the control air system that must maintain a pressure boundary in order to
 
supply the CAD and MSRVs
* establishes MSIV leakage pathway to the condenser
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.14, the applicant identified the following sampling and water quality system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings, flexible connectors, heat exchangers, piping, RCPB piping, pumps, strainers, tanks, tubing, valves, and RCPB valves.2.3.3.14.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.14 and UFSAR Sections 5.2.3, 5.3, 10.17, and 10.21 using the evaluation methodology described in SER Section 2.3. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had 2-88 not omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.14, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated October 8, 2004, the staff issued an RAI concerning
 
the specific issue to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAI and the applicant's related response.
In RAI F 2.3.3.14-1, the staff stated that LRA Section 2.3.3.14 states that one of the intended functions of the sampling and water quality system is to establish an MSIV leakage pathway to
 
the condenser. The Unit 2 sampling lines from the main steam system are identified as being
 
within the scope of license renewal and subject to an AMR; however, similar piping and
 
components for Unit 1 are not identified as being within the scope of license renewal. Based on
 
the information in the LRA, the staff could not determine why this portion of the Unit 1 sampling
 
and water quality system is not within the scope of license renewal and subject to an AMR.
 
Therefore, the staff requested that the applicant explain why this portion of the piping is not
 
within the scope of license renewal and subject to an AMR.
In its response, by letter dated October 25, 2004, the applicant stated that license renewal drawings depict components subject to an AMR based on the unit's CLB. As documented in
 
LRA Section F.1, the Unit 1 CLB for MSIV leakage does not incorporate an alternate leakage
 
treatment pathway utilizing main steam piping and the main condenser, because this
 
modification currently is not phy sically implemented for Unit 1 to match Units 2 and 3 in their configuration.
The LRA was structured to reflect CLB and configuration of all three units. Therefore, scoping and screening was done based on the CLB and configuration of all three units. The differences
 
between the units that are relevant to the application and will be resolved prior to Unit 1 restart
 
are listed in LRA Appendix F. This issue will be discussed in SER Section 2.6.1.1.
In addition, by letter dated January 31, 2005, the applicant provided additional supplementary information, stating that as each activity identified in LRA Appendix F is completed, the
 
corresponding bold-bordered text in the LRA will apply to Unit 1. The applicant stated in its
 
response that the only change to the application will be to remove the bolded border. No
 
changes are required for scoping and screening, AMR, or TLAAs; however, in some cases, boundary drawings would change to reflect the bolded bordered text. The applicant committed
 
to perform a secondary application review for the staff during the annual update after the
 
modification is implemented in the plant. This w ill assure that the design changes to implement this modification do not modify or change the basis of how these components were initially
 
scoped and screened.
Based on its review, the staff found the applicant's response to RAI F 2.3.3.14-1 acceptable.
The Unit 1 CLB for MSIV leakage does not incorporate an alternate leakage treatment pathway
 
utilizing the main steam piping and main condenser; therefore, this portion of piping is not 2-89 subject to an AMR. Upon completion of the modification discussed in LRA Appendix F and the January 31, 2005 letter, the CLB for Unit 1 will be the same as that for Units 2 and 3. The review
 
of LRA Appendix F regarding Unit 1 restart will be addressed in SER Section 2.6.1.1. Therefore, the staff's concern described in RAI F 2.3.3.14-1 is resolved.
In order to resolve the seismic Class I/II interface issues discussed in RAI 2.1-2A(3) of SER Section 2.1, the applicant expanded the system boundaries for the sampling and water quality
 
system. By letters dated January 31, 2005, and February 28, 2005, the applicant submitted the
 
result of its review of the seismic Class I qualification documentation to identify the NSR piping, supports/equivalent anchors, or other components that are within the scope of license renewal
 
in accordance with the requirements of 10 CFR 54.4(a)(2) for the 10 CFR 54.4(a)(2) cases
 
where NSR piping or components are directly connected to SR piping or components. In
 
February 28, 2005, letter, Enclosure 2, "Mechanical Systems," the applicant stated that
 
additional components, grab sample boxes, had been added to scope that are credited as
 
anchorage in the seismic analysis. As a result, the component type panel was added to LRA
 
Table 2.3.3.14.
The staff reviewed the identify support/equivalent anchors and the seismic Class II piping segments up to the first anchor point of the seismic Class I piping boundaries provided in the of the letter, dated February 28, 2005. The staff found the expanded scope of
 
components to be acceptable because the applicant had adequately included NSR components
 
with the configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where
 
NSR piping or components are directly connected to SR piping or components.
2.3.3.14.3  Conclusion
 
The staff reviewed the LRA and RAI responses described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the
 
applicant. No omissions were identified. In addition, the staff performed a review to determine
 
whether any components that should be subject to an AMR had not been identified by the
 
applicant. No omissions were identified. On the basis of its review, the staff concluded that there
 
is reasonable assurance that the applicant had adequately identified the sampling and water
 
quality system components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the sampling and water quality system components that are subject to an
 
AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.15  Building Heat System 2.3.3.15.1  Summary of Technical Information in the Application In LRA Section 2.3.3.15, the applicant described the building heat system. The building heat system is a plant-shared system that main tains the required temperatures for equipment protection and personnel comfort during the winter months. As required, the system uses forced, hot water to maintain a minimum temperature of 55 °F in various plant buildings, including the reactor building. Hot water required for the system is heated by the auxiliary boiler system and preheats the building intake air.
The building heat system contains SR components that are relied upon to remain functional during, and following, DBEs.
2-90 The intended functions within the scope of license renewal include the following:
* provides a secondary containment boundary
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.15, the applicant identified the following building heat system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, heaters, piping, pumps, and valves.
2.3.3.15.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.15 and UFSAR Sections 5.3.3.6 and 10.12.5 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.15, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning
 
the specific issue to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAI and the applicant's related response.
In RAI 2.3.3.15-1, the staff stated that LRA Section 2.3.3.15 states that the intended function of the building heat system is to provide a secondary containment boundary. The staff identified
 
that valves 1-1029, 1-1030, 2-1318, 2-1319, 3-1386, and 3-1387 are included in the scope of
 
license renewal and subject to an AMR, but the connected piping on one side of these valves is
 
not included within the scope of license renewal and not subject to an AMR. The staff could not
 
determine if the piping on both sides of these open valves provides a secondary containment
 
boundary. Therefore, the staff requested that the applicant provide a basis for these valves
 
being the boundary of the piping and components that are not subject to an AMR.
In its response, by letter dated October 19, 2004, the applicant stated that valves 1-1029, 1-1030, 2-1318, 2-1319, 3-1386, and 3-1387 were included in the scope of license renewal in
 
error and that only the piping and valves for the building heat system located in the reactor
 
building perform a secondary containment function. Valves 1-1029, 1-1030, 2-1318, 2-1319, 3-1386, and 3-1387 are located in the turbine building and, therefore, are not within the scope of
 
license renewal. The applicant also stated that drawing 0-47E866-1-LR has been revised to
 
show the boundary ending at the reactor building wall and will be resent as part of the annual
 
update.
2-91 Based on its review, the staff found the applicant's response to RAI 2.3.3.15-1 acceptable.
Valves 1-1029, 1-1030, 2-1318, 2-1319, 3-1386, and 3-1387 do not perform an intended
 
function in accordance with the requirements of 10 CFR 54.4(a) and are outside the scope of
 
license renewal. Therefore, the staff's concern described in RAI 2.3.3.15-1 is resolved.
2.3.3.15.3  Conclusion
 
The staff reviewed the LRA and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the building heat system
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the building heat system components that are subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3.3.16  Raw Water Chemical Treatment System 2.3.3.16.1  Summary of Technical Information in the Application In LRA Section 2.3.3.16, the applicant described the raw water chemical treatment system. The raw water chemical treatment system prevents bio-fouling of systems, including the EECW and RHRSW systems, that use water directly from Wheeler Reservoir. The raw water chemical treatment system provides the capability to inject a biocide into the fluid stream.
The raw water chemical treatment system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the raw water
 
chemical treatment system could prevent the sa tisfactory accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides for pressure boundary integrity to the RHRSW and EECW systems
* restricts flow
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.16, the applicant identified the following raw water chemical treatment system component types that are within the scope of license renewal and subject to an AMR:
bolting, fittings, piping, restricting orifice, and valves.
2.3.3.16.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.16 and UFSAR Sections 10.7.3, 10.8.4, and 10.10.4 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
2-92 In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.16.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In
 
addition, the staff performed a review to determine whether any components that should be
 
subject to an AMR had not been identified by the applicant. No omissions were identified. On
 
the basis of its review, the staff concluded that there is reasonable assurance that the applicant
 
had adequately identified the raw water chemical treatment system components that are within
 
the scope of license renewal, as required by 10 CFR 54.4(a), and the raw water chemical
 
treatment system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.17  Demineralizer Backwash Air System 2.3.3.17.1  Summary of Technical Information in the Application In LRA Section 2.3.3.17, the applicant described the demineralizer backwash air system. The demineralizer backwash air system is a plant-shar ed system that supplies a high volume of low pressure air for purpose of backwashing plant demineralizers. In addition, the system supplies
 
the condensate demineralizers in the turbine building and penetrates the secondary
 
containment to supply the reactor water cleanup (RWCU) and fuel pool cooling and cleanup (FPC) demineralizers in the reactor building.
The demineralizer backwash air system is in standby operation during normal operation and is operated manually, when required, for
 
backwashing of the demineralizers.
The demineralizer backwash air system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the demineralizer backwash
 
air system could prevent the satisfacto ry accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides a secondary containment boundary
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.17, the applicant identified the following demineralizer backwash air system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, piping, traps, and valves.
2-93 2.3.3.17.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.17 and UFSAR Section 5.3.3 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.17.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In
 
addition, the staff performed a review to determine whether any components that should be
 
subject to an AMR had not been identified by the applicant. No omissions were identified. On
 
the basis of its review, the staff concluded that there is reasonable assurance that the applicant
 
had adequately identified the demineralizer backwash air system components that are within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and the demineralizer backwash air
 
system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.18  Standby Liquid Control System 2.3.3.18.1  Summary of Technical Information in the Application In LRA Section 2.3.3.18, the applicant descri bed the SLC system. The SLC system provides a backup method, independent of the control rods, to make the reactor subcritical over the full
 
range of operating conditions. The SLC system can be manually initiated from the main control room to pump a boron neutron absorber solution into the reactor. This function is initiated if the
 
operator determines that the reactor cannot be shut down or kept shut down with the control
 
rods alone. During normal operation, the SLC system is in standby and must be manually
 
initiated, if required.
The SLC system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the SLC system could prevent the satisfactory
 
accomplishment of an SR function. In addition, the SLC system performs functions that support
 
ATWS. The intended functions within the scope of license renewal include the following:
* provides RCPB
* provides a primary containment boundary
* provides mechanical closure
* provides pressure boundary
* provides structural support 2-94 In LRA Table 2.3.3.18, the applicant identified the following SLC component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings, piping, RCPB piping, pumps, tanks, tubing, valves, and RCPB valves.
2.3.3.18.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.18 and UFSAR Sections 3.8, 5.2.3, and 7.19 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.18, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning
 
the specific issue to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAI and the applicant's response.
In RAI 2.3.3.18-1, the staff stated that component electric heaters, located inside the SLC tank, are shown on license renewal drawings 1-47E854-1-LR, 2-47E854-1-LR, and 3-47E854-1-LR as subject to an AMR. However, LRA Section 2.3.5 lists the component UNID of the heater in
 
three different component types (fittings, heaters, or tanks). Therefore, the staff requested that
 
the applicant identify which component type in LRA Table 2.3.3.18 includes the electric heater.
 
Furthermore, during a telephone conference on October 7, 2004, the staff requested that the
 
applicant justify the exclusion of a strainer, addressed in UFSAR Section 3.8.3 but not depicted
 
on the license renewal drawings or included in LRA Table 2.3.3.18, from the scope of license
 
renewal and from being subject to an AMR.
In its response, by letter dated October 19, 2004, the applicant stated that this heater is included in the component type "fittings" in LRA Table 2.3.3.18. The staff requested the
 
applicant to verify that the heaters are, in fact, included in the component type "fittings." In a
 
supplemental response, dated June 9, 2005, the applicant confirmed that the heaters are included in component type "fittings" in LRA Table 2.3.3.18 and are so documented in the
 
Standby Liquid Control System Report. The applic ant also provided information that the strainers have been included in LRA Table 2.3.3.18 for being subject to an AMR. Based on its review, the staff found the applicant's response to RAI 2.3.3.18-1 acceptable. It clarifies that the heater is included in the component type "fittings" in the LRA table, and it
 
includes the strainer within the scope of license renewal and subject to an AMR. Therefore, the
 
staff's concerns described in RAI 2.3.3.18-1 and the October 7, 2004, telephone discussion are
 
resolved.
2-95 In order to resolve the seismic Class I/II interface issues discussed in RAI 2.1-2A(3) of SER Section 2.1, the applicant expanded the system boundaries for the standby liquid control
 
system. By letters dated January 31, 2005, and February 28, 2005, the applicant submitted its
 
review result of the documentation of the seismic Class I qualification to identify the NSR piping, supports/equivalent anchors, or other components that are within the scope of license renewal
 
in accordance with the requirements of 10 CFR 54.4(a)(2) for the cases where NSR piping or
 
components are directly connected to safety-related piping or components. In its February 28, 2005 letter, enclosure 2, "Mechanical Systems," the applicant stated that additional piping and
 
components had been added to the scope of the standby liquid control system. However, the
 
component types do not differ from those listed LRA Table 2.3.3.18; therefore, no changes to
 
the standby liquid control system portion in the LRA are required.
The staff reviewed the NSR piping up to first equivalent anchor point of seismic Class I piping boundaries and found the expanded scope of components to be acceptable on the basis that
 
the applicant had adequately identified all SLC NSR components that meet the scoping criterion
 
of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to
 
SR piping or components.
2.3.3.18.3  Conclusion
 
The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI responses described above to determine whether any SSCs that should be within the scope of license
 
renewal had not been identified by the applicant. No omissions were identified. In addition, the
 
staff performed a review to determine whether any components that should be subject to an
 
AMR had not been identified by the applicant. No omissions were identified. On the basis of its
 
review, the staff concluded that there is reasonable assurance that the applicant had adequately
 
identified the SLC system components that are within the scope of license renewal, as required
 
by 10 CFR 54.4(a), and the SLC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.19  Off-Gas System 2.3.3.19.1  Summary of Technical Information in the Application In LRA Section 2.3.3.19, the applicant described the off-gas system. Each unit has a separate off-gas system, which includes subsystems that process and dispose of the gases produced
 
during normal operation from the main condenser steam jet air ejectors, the startup condenser
 
vacuum pumps, the condensate drain tank v ent, and the steam packing exhauster. The gases are processed to minimize any release of harmful radioactivity and are then diverted to the plant
 
stack for dilution and release to the atmosphere at elevation. Backdraft dampers limit the
 
amount of radioactive release at ground level during accidents that require operation of the SGT system.The off-gas system contains SR components that are relied upon to remain functional during, and following, DBEs.
2-96 The intended functions within the scope of license renewal include the following:
* provides flow path integrity for the release of the filtered SGT system gases to the stacks
* provides automatic closure of back-dr aft prevention dampers to prevent back-flow and potential ground-level release of radiation
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.19, the applicant identified the following off-gas system component types that are within the scope of license renewal and subject to an AMR: bolting, ductwork, fittings, and piping.
2.3.3.19.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.19 and UFSAR Sections 1.6.1.1.10, 1.6.1.4.4, 5.3.3, 7.12.2, 7.12.3, 9.5, 11.4, 14.6.3.6, and F.7.14 using the evaluation methodology described in
 
SER Section 2.3. The staff conducted its review in accordance with the guidance described in
 
SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In order to resolve the seismic Class I/II interface issues discussed in RAI 2.1-2A(3) of SER Section 2.1, the applicant expanded the system boundaries for the off-gas system. By letters dated January 31, 2005, and February 28, 2005, the applicant submitted the results of its review
 
of the seismic Class I qualification documentation to identify the NSR piping, supports/equivalent anchors, or other components that are within the scope of license renewal
 
in accordance with the requirements of 10 CFR 54.4(a)(2) for the cases where NSR piping or
 
components are directly connected to SR piping or components. In the February 28, 2005 letter, enclosure 2, "Mechanical Systems," the applic ant stated that additional components, valves, had been added to the scope of the off-gas system. The component type valve was added to
 
LRA Table 2.3.3.19.
The staff reviewed the NSR piping up to first equivalent anchor point of seismic Class I piping boundaries and found the expanded scope of components to be acceptable on the basis that
 
the applicant had adequately identified all SLC NSR components that meet the scoping criterion
 
of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to
 
SR piping or components.
2-97 2.3.3.19.3  Conclusion The staff reviewed the LRA and RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff performed a review to determine whether any components that
 
should be subject to an AMR had not been identified by the applicant. No omissions were
 
identified. On the basis of its review, the staff concluded that there is reasonable assurance that
 
the applicant had adequately identified the off-gas system components that are within the scope
 
of license renewal, as required by 10 CFR 54.4(a), and the off-gas system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.20  Emergency Equipment Cooling Water System 2.3.3.20.1  Summary of Technical Information in the Application In LRA Section 2.3.3.20, the applicant descr ibed the EECW system. The EECW system is a plant-shared system, which has two headers that use dedicated RHRSW pumps to supply water
 
from the Wheeler Reservoir into heat exchangers. The heat exchangers cool equipment including the DG engine coolers, CS pump room coolers, RHR pump seal coolers and room
 
coolers, control bay chillers, hydrogen and oxygen containment gas analyzers, and electric
 
board room chillers. The EECW system provides coo ling water to equipment that is essential for safe shutdown and a backup cooling water supply to the reactor building closed cooling water
 
heat exchangers.
The EECW system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the EECW system could prevent the
 
satisfactory accomplishment of an SR func tion. In addition, the EECW system performs functions that support fire protection, EQ, and SBO.
The intended functions within the scope of license renewal include the following:
* provides cooling water to the HVAC system chillers, RHR system pump seal coolers, containment inerting system hydrogen and oxygen gas analyzers, DG, RHR and CS equipment room coolers, and FPC system
* provides an EECW valve position interlock signal for automatic start of the RHRSW pumps
* provides a secondary containment boundary
* prevents debris from entering a system or component
* provides for flow distribution
* provides for heat transfer
* provides mechanical closure
* provides pressure boundary
* provides structural support 2-98 In LRA Table 2.3.3.20, the applicant identified the following EECW system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, flexible
 
connectors, heat exchangers, piping, restricting orifice, strainers, tubing, and valves.
2.3.3.20.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.20 and UFSAR Sections 5.3, 7.18, 10.10, and F.7.17 using the evaluation methodology described in SER Section 2.3. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.20, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning
 
the specific issue to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAI and the applicant's response.
In RAI 2.3.3.20-1, the staff stated that License renewal drawings 1-47E859-1-LR, 2-47E859-1-LR, and 3-47E859-1-LR depict the EECW system. The cooling water return piping
 
from the SR components terminates at lo cations designated as "yard drainage." LRA Table 3.3.2.20 indicates that buried carbon and low-alloy steel piping has been evaluated for
 
aging management. However, neither the LRA nor the associated drawings adequately identify
 
the extent of the buried piping subject to an AMR. Therefore, the staff requested that the
 
applicant identify the extent of the buried piping and provide an appropriately marked license
 
renewal drawing, or identify a specific structure where the piping subject to an AMR terminates.
 
The staff also requested that the applicant justify the exclusion of any buried piping or structures
 
between the emergency equipment cooling water system and the final discharge structure from
 
the scope of license renewal and from being subject to an AMR.
In its response, by letter dated October 19, 2004, the applicant stated that a note had been added to license renewal drawings 1-47E859-1-LR, 2-47E859-1-LR, and 3-47E859-1-LR to state that the EECW buried piping is within the scope of license renewal up to the catch basins
 
shown on isometric drawing 0-17W300-9.
Based on its review, the staff found the applicant's response to RAI 2.3.3.20-1 acceptable. It adequately identifies the extent of the buried emergency equipment cooling water piping that is
 
within the scope of license renewal and subject to an AMR. Therefore, the staff's concern
 
described in RAI 2.3.3.20-1 is resolved.
2-99 2.3.3.20.3  Conclusion The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI response described above to determine whether any SSCs that should be within the scope of license
 
renewal had not been identified by the applicant. No omissions were identified. In addition, the
 
staff performed a review to determine whether any components that should be subject to an
 
AMR had not been identified by the applicant. No omissions were identified. On the basis of its
 
review, the staff concluded that there is reasonable assurance that the applicant had adequately
 
identified the EECW system components that are within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and the EECW system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.21  Reactor Water Cleanup System 2.3.3.21.1  Summary of Technical Information in the Application In LRA Section 2.3.3.21, the applicant described the RWCU system. A separate RWCU system is provided for each unit. The major equipment for the RWCU system is located in the reactor
 
building and consists of two pumps, regener ative and non-regenerative heat exchangers, and two filter/demineralizers with supporting equipmen
: t. Suction for the system is taken from the reactor vessel bottom drain and from the RHR system shutdown cooling suction line, which is
 
supplied by the reactor coolant recirculation system. The system autom atically isolates upon accident initiation and upon SLC system actuation. The RWCU system functions to maintain a
 
high reactor-water purity to limit corrosion, chemical interactions, fouling, and deposits on
 
reactor heat transfer surfaces. The system also removes corrosion products to limit impurities
 
available for activation by neutron flux and the resultant radiation from deposits of corrosion
 
products. In addition, the system provides a means for removal of water from the reactor vessel
 
during normal operations.
The RWCU system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the RWCU system could prevent the
 
satisfactory accomplishment of an SR function. In addition, the RWCU system performs
 
functions that support fire protection, EQ, and SBO.
The intended functions within the scope of license renewal include the following:
* provides primary and secondary containment boundaries
* provides RCPB
* provides system pressure boundary support (check valve) to HPCI to prevent diversion of HPCI system core cooling water from the reactor vessel (Unit 3 only)
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.21, the applicant identified the following RWCU system component types
 
that are within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB 2-100 fittings, heat exchangers, piping, RCPB piping, pumps, restricting orifice, strainers, tanks, traps, tubing, valves, and RCPB valves.
2.3.3.21.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.21 and UFSAR Sections 3.8, 4.1, 4.9, 5.2.3, 5.3, and 7.3 using the evaluation methodology described in SER Section 2.3. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.21, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated April 8, 2005, the staff issued RAIs concerning the
 
specific issues to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAIs and the applicant's related responses.
In RAI 2.3.3.21-1, the staff identified thermal tees that are within the scope of license renewal and subject to an AMR. However, "thermal tees" is not a component type listed in LRA
 
Table 2.3.3.21-1 as being subject to an AMR, nor it is included in LRA Section 2.3.5 as a
 
component type. Therefore, the staff requested that the applicant indicate if thermal tees are
 
already included in LRA Table 2.3.3.21 as a component type subject to an AMR, or justify the
 
exclusion of the components from being subject to an AMR in accordance with the requirements
 
of 10 CFR 54.21(a)(1).
In its response, by letter dated April 28, 2005, the applicant stated that thermal tees are included in LRA Table 2.3.3.21 as component type "fittings." Thermal tees were not listed in
 
LRA Section 2.3.5, because these components are not assigned UNID's on drawings. LRA
 
Section 2.3.5 was generated to show where UNID's appearing on the license renewal drawings
 
were grouped in a component type.
Based on its review, the staff found the applicant's response to RAI 2.3.3.21-1 acceptable.
because thermal tees are included as a component type that is subject to an AMR. Therefore, the staff's concern described in RAI 2.3.3.21-1 is resolved.
In RAI 2.3.3.21-2, the staff identified fusible plugs (FUPG) to be within the scope of license renewal and subject to an AMR. The drawing note associated with FUPGs states that the FUPG
 
is a threaded pipe plug with a low temperature eutectic alloy that is attached to the RWCU pipe
 
upstream of valve FCV-69-94. Eutectic material melts on high temperature, venting the control
 
air line, which closes isolation valve FCV-69-94. Also, another drawing note states that the
 
system shall be qualified for an elevated temperature excursion up to 562 °F during an Appendix R event from the non-generative heat exchanger outlet to valve FCV-69-94.
2-101  a.The FUPGs are neither listed in LRA Table 2.3.3.21 as a component type subject to an AMR, nor as a subcomponent of the component types listed in LRA Section 2.3.5.
 
Therefore, the staff requested that the applicant indicate if FUPGs are already included
 
in LRA Table 2.3.3.21 as a component type subject to an AMR, or justify the exclusion of
 
these components from being subject to an AMR in accordance with the requirements of
 
10 CFR 54.21(a)(1). b.Based on the above mentioned drawing notes, it appears that valve FCV-69-94 satisfies criterion 10 CFR 54.4(a)(3) for an EQ and fire protection regulated event. However, the
 
piping and components associated with this valve, including the above-mentioned
 
FUPG, are shown as within the scope of license renewal in accordance with the
 
10 CFR 54.4(a)(2) criterion. The staff requested that the applicant explain how valve
 
FCV-69-94 functions differently from its associated pipeline.
In its response, by letter dated April 28, 2005, the applicant stated that the FUPGs were inadvertently colored in blue on the drawing but should have been black since they are active components and are not within the scope of license renewal. The applicant also stated that the
 
fusible plugs do not form a pressure boundary function for the RWCU system. The license
 
renewal drawings have been revised to show FUPG-32-5105 black instead of blue, since it is
 
not subject to an AMR.
Based on its review, the staff found the applicant's response to RAI 2.3.3.21-2a acceptable.
FUPGs meet the definition for an active component and, therefore, are not subject to an AMR.
 
Therefore, the staff's concern described in RAI 2.3.3.21-2a is resolved.
With regard to RAI 2.3.3.21-2b, the applicant stated that the piping and equipment downstream of FCV-69-2 up to and including valve FCV-69-94 will be corrected on the drawings to show the
 
components in scope per the criteria 10 CFR 54.4a(3) and subject to an AMR, since these
 
components form the reactor coolant pressure boundary during an Appendix R event. The tube
 
side of the heat exchanger is considered part of the reactor coolant pressure boundary while the
 
shell side provides the structural support for the tubes. Shell side piping connections will remain
 
in scope. Also, System 43 in drawing 0-105E3156-1-LR will be corrected to show its
 
components required for pressure boundary integrity in red instead of blue on the drawing, that
 
are within the scope of license renewal and subject to an AMR, due to its interface with RWCU
 
drawings 2-47E810-1-LR and 3-47E810-1-LR.
Based on its review, the staff found the applicant's response to RAI 2.3.3.21-2b acceptable. The applicant clarified the function of the piping and valve in question and corrected the
 
corresponding drawings to reflect the appropriate intended function of the components.
 
Therefore, the staff's concern described in RAI 2.3.3.21-2b is resolved.
In RAI 2.3.3.21-3, the staff stated that UFSAR (Revision 20), Section 4.9 states that:
Reactor coolant is continuously removed from the reactor coolant recirculation system, cooled in the regenerativ e and non-regenerative heat exchangers, filtered and demineralized, and returned to the feedwater system through the
 
shell side of the regenerative heat exchanger. The Unit 3 RWCU system has the
 
capability to return process fluid to the feedwater system through both reactor 2-102 feedwater lines A and B. The Unit 2 RWCU system only has one return line through reactor feedwater line B.
Only, the RWCU system return line to the reactor feedwater line B is depicted on license renewal drawing 3-47E810-1-LR. Therefore, the staff requested that the applicant indicate
 
whether feedwater line A is within the scope of license renewal and subject to an AMR, or
 
provide an explanation for its exclusion. The staff also asked the applicant to provide an
 
alternative drawing that shows the RWCU system return to feedwater line A for Unit 3.
In its response, by letter dated April 28, 2005, the applicant stated that the Unit 3 RWCU system return to feedwater line A is shown on license renewal drawing 3-47E810-1-LR (at location G6).
 
The applicant further noted that the return is through a HPCI line shown on 3-47E812-1-LR (location E6) which connects to feedwater line A shown on 3-47E803-1-LR (location G6). The
 
HPCI and feedwater portions of this return path are within the scope of license renewal.
Based on its review, the staff found the applicant's response to RAI 2.3.3.21-3 acceptable. The applicant identified the return to feedwater line A and stated that it is within the scope of license
 
renewal as indicated on the provided license renewal drawings. Therefore, the staff's concern
 
described in RAI 2.3.3.21-3 is resolved.
In RAI 2.3.3.21-4, the staff identified flow indicators FI-85-75 and FI-85-77, and flow element FE-69-13 as excluded from the scope of license renewal. The flow indicators and flow element serve an intended function of pressure boundary and are passive and long-lived components. It
 
is noted that similar flow indicators and flow elements on drawings 2-47E810-1-LR and 3-47E810-1-LR are shown to be within the scope of license renewal and subject to an AMR.
 
However, "flow indicators" is not listed in LRA Table 2.3.3.21 as a component type subject to an
 
AMR, nor as a subcomponent of the component types listed in LRA Section 2.3.5. Therefore, the staff requested that the applicant:  a.Justify the exclusion of the aforementioned flow indicators and flow element in Unit 1 from the scope of license renewal and from being subject to an AMR in accordance with
 
the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively. b.Clarify whether flow indicators are included in other component types already listed in LRA Table 2.3.3.21, or justify their exclusion from an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
In its response, by letter dated April 28, 2005, the applicant stated that NEI 95-10, Appendix B indicates that flow indicators are active components. FI 85-75 and FI 85-77 were colored blue in
 
error on license renewal drawings 2-47E810-1-LR and 3-47E810-1-LR, but have been corrected
 
to show these components black on the drawings; that is, not subject to an AMR. The flow
 
element on license renewal drawing 1-47E810-1-LR was included as a fitting in the evaluation
 
but was inadvertently not colored blue on the drawing. License renewal drawing 1-47E810-1-LR has also been revised to show that FE 69-13 is within the scope of license renewal and subject
 
to AMR.
 
With regard to RAI 2.3.3.21-4b, the applicant stated that "flow indicators" is not a component
 
type listed in LRA Table 2.3.3.21. Flow indicators were excluded from an AMR based on
 
guidance provided in NEI 95-10 Appendix B.
2-103 On the basis of this review, the staff was unable to find the applicant's response to RAI 2.3.3.21-4 acceptable. The applicant follows the guidance in NEI 95-10, which lists flow
 
indicators as active components. However, the flow indicators in question are in-line indicators.
 
The indicator portion of the component is an active component, but the piping portion of the
 
indicator through which reactor water flows provides a pressure boundary function. Therefore, this portion of the component should be within the scope of license renewal and subject to an
 
AMR. In a follow-up question, the staff asked the applicant to justify the exclusion of the piping
 
portion of the flow indicators.
In a follow-up response, by letter dated May 24, 2005, the applicant stated that the pressure boundary portion of the flow indicators are in scope and are evaluated as fittings in the CRD
 
system (system 85). License renewal drawings 1-47E810-1-LR, 2-47E810-1-LR, and 3-47E810-1-LR were revised to show that FI-75 and FI-77 are in scope and subject to an AMR
 
for meeting the10 CFR 54.4(A)(2) criterion. The pressure retaining portion of the flow indicators
 
are stainless steel with internal environment of treated water, with external environment of inside air, and are already contained in LRA Table 3.3.2.29. The applicant further stated that all
 
license renewal drawings were reviewed for in-line flow indicators that provide a pressure
 
boundary function. This review identified the drawings for systems 43, 68, 69, and 74 that
 
contain flow indicators with pressure boundary functions. The applicant stated that no changes
 
to LRA tables are required since fittings contain the material and environment combinations for
 
the in-line flow indicators, flow indicating controllers, and flow indicating switches that provide a
 
pressure boundary function.
Based on its review, the staff found the applicant's response to RAI 2.3.3.21-4 acceptable. The applicant included the flow indicators within the scope of license renewal and subject to an
 
AMR. The applicant also performed a review for all other mechanical systems and identified the
 
systems with flow indicators that form a pressure boundary. The applicant revised the system
 
drawings accordingly by adding these flow indicators in scope. Therefore, the staff's concern
 
described in RAI 2.3.3.21-4 is resolved In RAI 2.3.3.21-5, the staff identified a 4-inch pipeline to the waste collector and surge tank inside the pipe tunnel to radwaste (location B4) excluded from the scope of license renewal.
 
However, the same pipeline on the license renewal drawing is shown as being within the scope
 
of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2). Therefore, the
 
staff requested that the applicant clarify this apparent discrepancy.
In its response, by letter dated April 28, 2005, the applicant stated that the line was inadvertently colored in blue but should have been in black. The drawing was corrected to show
 
the line in black, that is, not within the scope of license renewal.
Based on its review, the staff found the applicant's response to RAI 2.3.3.21-5 acceptable. The applicant clarified that the piping in question is not within the scope of license renewal and
 
corrected the corresponding drawing. Therefore, the staff's concern described in RAI 2.3.3.21-5
 
is resolved.
2.3.3.21.3  Conclusion
 
The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI responses described above to determine whether any SSCs that should be within the scope of license 2-104 renewal had not been identified by the applicant. No omissions were identified. In addition, the staff performed a review to determine whether any components that should be subject to an
 
AMR had not been identified by the applicant. No omissions were identified. On the basis of its
 
review, the staff concluded that there is reasonable assurance that the applicant had adequately
 
identified the RWCU system components that are within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and the RWCU system components that are subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3.3.22  Reactor Building Closed Cooling Water System 2.3.3.22.1  Summary of Technical Information in the Application In LRA Section 2.3.3.22, the applicant described the reactor building closed cooling water system. The reactor building closed cooling wa ter system provides a continuous supply of cooling water during normal operation to designated plant equipment located in the primary and
 
secondary containments. Water cooled in the heat exchangers provides cooling water for
 
components such as the reactor recirculation system pumps and motor, the RWCU system
 
pumps and non-regenerative heat exchanger, the fuel pool cooling and cleanup system heat exchanger, the drywell atmosphere cooling coils, the reactor building equipment drain sump
 
heat exchanger, the drywell equipment drain sump heat exchanger, the drywell air compressors
 
and aftercoolers, and the sample coolers in the sampling and water quality system. The system
 
is normally operational and will automatically trip if an accident initiates it.
The reactor building closed cooling water system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the reactor
 
building closed cooling water system could prev ent the satisfactory accomplishment of an SR function. In addition, the reactor building closed cooling water system performs functions that
 
support fire protection, EQ, and SBO.
The intended functions within the scope of license renewal include the following:
* provides primary and secondary containment boundaries
* provides for a pressure boundary of the reactor building closed cooling water system components connected to the control air system that must maintain the boundary in
 
support of supplying CAD to the MSRVs
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.22, the applicant identified the following reactor building closed cooling water system component types that are within the scope of license renewal and subject to an
 
AMR: bolting, fittings, flexible connectors, heat exchangers, piping, pumps, strainers, tanks, tubing, and valves.
As a result of the review of seismic Class I piping boundaries to identify supports and equivalent anchors in response to RAI 2.1-2A(3) (discussed in SER Section 2.1), the applicant expanded
 
the system boundaries for the reactor building cl osed cooling water system. By letters dated 2-105 January 31, 2005, and February 28, 2005, the applicant submitted the results of its review of the seismic Class I qualification documentation to identify the NSR piping, supports and equivalent
 
anchors, or other components that are within the scope of license renewal in accordance with
 
the requirements of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are
 
directly connected to SR piping or components. In its February 28, 2005, letter, enclosure 2, "Mechanical Systems," the applicant stated that additional piping and components had been
 
added to the scope of the reactor building closed cooling water system. However, the
 
component types do not differ from those listed in LRA Table 2.3.3.22 and no changes to the
 
reactor building closed cooling water system portion of the LRA are required.
2.3.3.22.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.22 and UFSAR Sections 5.2, 5.3, 10.6, and F.6.19 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.22, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued RAIs concerning the
 
specific issues to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAIs and the applicant's related responses.
In RAI 2.3.3.22-1, the staff stated that license renewal drawings 2-47E610-70-1-LR and 3-47E610-70-1-LR show that the flow control valves and the combination of air filter/pressure
 
regulators for the drywell atmospheric cooling units (A5 and B5) are within the scope of license
 
renewal and subject to an AMR. However, the flow control valves and combination of the air
 
filter/pressure regulators for the drywell atmospheric cooling units A4 and B4, A3 and B3, A2
 
and B2, and A1 and B1 are not identified as being within the scope of license renewal.
 
Therefore, the staff requested that the applicant justify the exclusion of the flow control valves
 
and combination air filter/pressure regulators for the drywell atmospheric cooling units A4 and
 
B4, A3 and B3, A2 and B2, A1 and B1 components from the scope of license renewal and from
 
being subject to an AMR.
In its response, by letter dated October 19, 2004, the applicant stated that the air filter/pressure regulators for drywell atmospheric cooling units A1 and B1, A2 and B2, A3 and B3, and A4 and
 
B4 are not within the scope of license renewal, because they do not form a pressure boundary
 
with the control air system (system 32).
2-106 Based on its review, the staff was unable to find the applicant's response to RAI 2.3.3.22-1 acceptable, because a drawing note (Note 6 at location F2 on license renewal drawings
 
2-47E610-70-1-LR and 3-47E610-70-1-LR) states:
The cooling water enters the drywell, supplying two drywell atmospheric cooling units (A and B). Each Cooling Unit has five cooling coils, four operating and one
 
spare. Control is from the main control room by a hand switch (HS-70-16A, etc)
 
which operates dampers and diaphragm-operated gate valves (FCV-70-16, etc).
 
Each drywell cooling unit has five fans, any four of them may be used at one time
 
and the fifth reserved as a spare.
Any cooling unit can be used as a spare unit, and the configuration shown on the license renewal drawings for cooling units A5 and B5 can be applied to all other cooling units. Hence, cooling units A1 through A4 and B1 through B4 also form a pressure boundary with the control
 
air system when they are used as a spare unit. Ther efore, the air filter/pressure regulators for cooling units A1 through A4 and B1 through B4 should be within the scope of license renewal
 
and subject to an AMR. Considering the above-mentioned drawing note, the staff asked in a
 
supplemental RAI that the applicant justify the exclusion of cooling units A1 through A4, and B1
 
through B4 from the scope of license renewal and from being subject to an AMR.
In a supplemental response dated June 9, 2005, the applicant stated that, based upon further review, the filter/pressure regulators for cooling units A1 through A4, and B1 through B4 will be
 
included within the scope of license renewal, and that the license renewal drawings will be
 
revised accordingly.
Based on its review, the staff found the applicant's response to RAI 2.3.3.22-1 acceptable. The applicant added the filter/pressure regulators for cooling units A1 through A4, and B1 through
 
B4 to the scope of license renewal and will correct the corresponding drawings. Therefore, the
 
staff's concern described in RAI 2.3.3.22-1 is resolved.
In RAI 2.3.3.22-2, the staff stated that the operators of the two valves FCV 70-24 and FCV 70-34 are shown on license renewal drawings 2-47E610-70-1 and 3-47E822-1 as being within
 
the scope of license renewal and subject to an AMR. However, license renewal drawings
 
3-47E610-70-1, 1-47E822-1-LR, and 2-47E822-1-LR show the operators for the same valves as
 
not within the scope of license renewal and not subject to an AMR. T, the staff requested that
 
the applicant clarify the inconsistency and justify the exclusion of operators for FCV 70-24 and
 
FCV 70-34 from the scope of license renewal and from being subject to an AMR.
In its response, by letter October 19, 2004, the applicant stated that the operators shown on drawings 3-47E610-70-1-LR and 2-47E822-1-LR should have been highlighted, (i.e., that they
 
are in scope and subject to an AMR). The applicant further stated that the modification identified
 
in Appendix F.2 had not been implemented in Unit 1; therefore, these components are not within
 
the scope of license renewal for Unit 1. Dr awings 3-47E610-70-1-LR and 2-47E822-1-LR have been revised and will be sent to the staff as part of the annual update.
Based on its review, the staff found the applicant's response to RAI 2.3.3.22-2 acceptable. It concurs that the operators addressed in the RAI should be within the scope of license renewal.
 
Therefore, the staff's concern described in RAI 2.3.3.22-2 is resolved.
2-107 In RAI 2.3.3.22-3, the staff noted that LRA Section 2.3.3.22 states that the operators for the dampers are within the scope of license renewal as a pressure boundary for the control air. With
 
regard to this statement, the staff requested the following information:  a.The UNIDs assigned to various components, in particular, the dampers and the operators for the dampers, are for the reactor building closed cooling water system.
 
Therefore, the staff requested that the applicant clarify whether or not the operators for
 
the dampers are evaluated in the control air system. b.The staff also asked the applicant whether the operators shown on license renewal drawings 2-47E610-70-1-LR and 3-47E610-70-1-LR are subject to an AMR and, if so, under what component type.
In its response, by letter dated October 19, 2004, the applicant stated the following:
: a. The damper operators are part of the reactor building closed cooling water system, and are evaluated as valves in the reactor building closed cycle cooling water system. As
 
depicted on license renewal drawings 2-47E610-70-1-LR and 3-47E610-70-1-LR, the
 
damper operators support the control air system (system 32) pressure boundary. Since
 
these damper operators are connected to the control air system, they must maintain a
 
pressure boundary in order for the control air system to maintain its system boundary (i.e., form a pressure boundary). Therefore, any damper operators that are required to
 
form a pressure boundary with the control air system are within the scope of license
 
renewal for the control air system.
Based on its review, the staff found the applicant's response to RAI 2.3.3.22-3a acceptable. It clarifies that the damper operators have a pressure boundary intended function and are within
 
the scope of license renewal and subject to an AMR. Therefore, the staff's concern described in
 
RAI 2.3.3.22-3a is resolved.
In its response, by letter dated October 19, 2004, the applicant further stated the following:
: b. The damper operators are subject to an AMR and are included as part of the component type "valves" in LRA Table 2.3.3.22.
Based on its review, the staff found the applicant's response to RAI 2.3.3.22-3b acceptable. It confirms that the damper operators are subject to an AMR and are included in LRA
 
Table 2.3.3.22. Therefore, the staff's concern described in RAI 2.3.3.22-3b is resolved.
The staff also reviewed the results of the applicant's review of seismic Class I piping boundaries provided in the applicant's letter, dated February 28, 2005, enclosure 2, to identify supports and
 
equivalent anchor points in response to RAI 2.1-2A(3). The staff found the expanded scope of
 
components to be acceptable on the basis that the applicant had adequately identified all
 
reactor building closed cooling water system NSR components that meet the scoping criterion of
 
10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR
 
piping or components.
2-108 2.3.3.22.3  Conclusion The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI responses described above to determine whether any SSCs that should be within the scope of license
 
renewal had not been identified by the applicant. No omissions were identified. In addition, the
 
staff performed a review to determine whether any components that should be subject to an
 
AMR had not been identified by the applicant. No omissions were identified. On the basis of its
 
review, the staff concluded that there is reasonable assurance that the applicant had adequately
 
identified the reactor building closed cooling water system components that are within the scope
 
of license renewal, as required by 10 CFR 54.4(a), and the reactor building closed cooling water
 
system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.23  Reactor Core Isolation Cooling System 2.3.3.23.1  Summary of Technical Information in the Application In LRA Section 2.3.3.23, the applicant described the RCIC system. The RCIC system provides makeup water to the reactor vessel during shutdown and also provides isolation from the main
 
heat sink to supplement or replace the normal makeup water sources. The system also includes
 
associated valves and piping capable of delivering makeup water to the reactor vessel. During
 
normal operation, the system is in standby and initiates, automatically, when required. The RCIC system has automatic isolation provisi ons to ensure the integrity of the primary containment.
The RCIC system contains SR components that are relied upon to remain functional during, and following, DBEs. In addition, the RCIC system performs functions that support fire protection, EQ, ATWS, and SBO.
The intended functions within the scope of license renewal include the following:
* provides RCPB
* provides primary and secondary containment boundaries
* provides for a system pressure boundary in support of the residual heat removal system containment (torus) cooling function
* establishes MSIV leakage pathway to the condenser
* provides sufficient reactor coolant makeup to maintain the reactor in a safe condition
* provides debris protection
* restricts flow
* provides for heat transfer
* provides mechanical closure
* provides pressure boundary
* provides structural support 2-109 In LRA Table 2.3.3.23, the applicant identified the following RCIC system component types that are within the scope of license renewal and subject to an AMR: bolting, condenser, expansion
 
joint, fittings, RCPB fittings, flexible connector, heat exchangers, piping, RCPB piping, pumps, restricting orifice, RCPB restricting orifice, strainers, tanks, traps, tubing, turbines, valves, and
 
RCPB valves.
2.3.3.23.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.23 and the UFSAR Sections 4.1, 4.7, 5.2.3, 5.3, 7.3, and 7.18 using the evaluation methodology described in SER Section 2.3. The staff conducted its
 
review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omittedfrom the scope of license renewal any components with intended functions delineated under10 CFR 54.4(a). The staff then reviewed those com ponents that the applicant had identified as being within the scope of license renewal to verify that the applicant had not omitted any
 
passive and long-lived components that should be subject to an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.23, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated October 8, 2004, the staff issued an RAI concerning
 
the specific issues to determine whether the applicant had properly applied the scoping criteria
 
of 10 CFR 54.4 (a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAIs and the applicant's related responses.
In RAI 2.3.3.23-1, the staff stated that UFSAR Section 4.7.5, states that the RCIC makeup water is delivered into the reactor vessel through a connection to the feedwater line and is distributed
 
within the reactor vessel through the feedwater sparger. The connection to the feedwater line is
 
provided with a thermal sleeve. It is further stated that the thermal sleeve (liner) in the feedwater
 
line is designed as a nonpressure-containing liner and is provided to protect the
 
pressure-containing piping tee from excessive thermal stress. In LRA Table 2.3.3.23, thermal
 
sleeve (liner) was not identified as a component type within the scope of license renewal.
 
Therefore, the staff requested the applicant to include this component type within the scope of license renewal and AMR.
In its response, by letter dated November 3, 2004, the applicant stated that the material for this component was identified as pipe and pipe fitting in the feedwater system and will be inspected
 
as part of the One-Time Inspection Program.
Based on its review, the staff found the applicant's response to RAI 2.3.3.23-1 acceptable. The applicant included the subject component and its intended functions within the scope requiring
 
an AMR. Therefore, the staff's concern described in RAI 2.3.3.23-1 is resolved.
2.3.3.23.3  Conclusion
 
The staff reviewed the LRA and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No 2-110 omissions were identified. In addition, the staff performed a review to determine whether any components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the RCIC system
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the RCIC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.24  Auxiliary Decay Heat Removal System 2.3.3.24.1  Summary of Technical Information in the Application In LRA Section 2.3.3.24, the applicant described the auxiliary decay heat removal (ADHR) system. The ADHR system can be used to remove residual heat from the spent fuel pool and
 
reactor cavity during outages. The ADHR system supplements the fuel pool cooling and cleanup
 
system and consists of two cooling water loops. The primary cooling loop circulates water from
 
the spent fuel pool entirely inside the reactor building and rejects heat from the spent fuel pool
 
to a secondary loop via a heat exchanger. The secondary loop transfers heat to the atmosphere
 
outside of the reactor building by the means of evaporative cooling towers.
The ADHR system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the ADHR system could prevent the
 
satisfactory accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides a secondary containment boundary
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.24, the applicant identified the following ADHR system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, heat
 
exchangers, piping, pumps, strainers, tubing, and valves.
2.3.3.24.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.24 and UFSAR Sections 5.3, 10.5, and 10.22 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2-111 In order to resolve the seismic Class I/II interface issues discussed in RAI 2.1-2A(3) of SER Section 2.1, the applicant expanded the system boundaries for the ADHR system. By letters dated January 31, 2005, and February 28, 2005, the applicant submitted the results of its review
 
of the seismic Class I qualification documentation to identify the NSR piping, supports and
 
equivalent anchors, or other components that are within the scope of license renewal in
 
accordance with the requirements of 10 CFR 54.4(a)(2) for the 10 CFR 54.4(a)(2) cases where
 
NSR piping or components are directly connected to SR piping or components. In its
 
February 28, 2005, letter, enclosure 2, "Mechanical Systems," the applicant stated that
 
additional piping and components had been added to the scope of the ADHR system; however, the component types do not differ from those listed in LRA Table 2.3.3.24 and no changes to
 
the ADHD system portion of the LRA are required.
The staff reviewed the NSR piping up to first equivalent anchor point of seismic Class I piping boundaries and found the expanded scope of components to be acceptable on the basis that
 
the applicant had adequately identified all SLC NSR components that meet the scoping criterion
 
of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to
 
SR piping or components.
2.3.3.24.3  Conclusion
 
The staff reviewed the LRA and RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff performed a review to determine whether any components that
 
should be subject to an AMR had not been identified by the applicant. No omissions were
 
identified. On the basis of its review, the staff concluded that there is reasonable assurance that
 
the applicant had adequately identified the ADHR system components that are within the scope
 
of license renewal, as required by 10 CFR 54.
4(a), and the ADHR system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.25  Radioactive Waste Treatment System 2.3.3.25.1  Summary of Technical Information in the Application In LRA Section 2.3.3.25, the applicant described the radioactive waste treatment system. The radioactive waste treatment system is comprised of subsystems that process solid and liquid
 
radwaste that is generated during normal plant operation. The subsystems are plant-shared systems.The radioactive waste treatment system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the radioactive waste
 
treatment system could prevent the satisfactory accomplishment of an SR function. In addition, the radioactive waste treatment system performs functions that support fire protection, EQ, and SBO.The intended functions within the scope of license renewal include the following:
* provides primary and secondary containment boundaries 2-112
* provides piping interface integrity with the SGT system and the off-gas system in support of the release of filtered SGT gases through the stack
* provides a pressure boundary of the radioactive waste treatment system components connected to the control air system that must maintain a pressure boundary in support of
 
supplying CAD to the MSRVs
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.25, the applicant identified the following radioactive waste treatment system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, heat exchangers, piping, pumps, restricting orifices, tanks, strainers, tubing, and valves.
2.3.3.25.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.25 and UFSAR Sections 4.10, 5.2, 5.3, 9.1, 9.2, 9.3, 9.5, 10.16, F.6.7, F.6.8, F.6.20, and F.7.14 using the evaluation methodology described in SER
 
Section 2.3. The staff conducted its review in accordance with the guidance described in
 
SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In order to resolve the 10 CFR 54.4(a)(2) issues regarding NSR piping segments that support secondary containment discussed in RAI 2.1-2A(1) and (2) of SER Section 2.1, the applicant expanded the system boundaries for the radioactive waste treatment system. By letter dated May 31, 2005, the applicant submitted the NSR piping, supports, and other components outside secondary containment required to maintain the structural integrity of secondary containment that are within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2) for secondary containment qualification. In the enclosure to its letter dated May 31, 2005, the applicant stated that additional piping had been added to scope. However, the component type does not differ from those listed in LRA Table 2.3.3.25; therefore, no changes to the radioactive waste treatment system portion of the LRA are required.
The applicant also expanded the system boundaries fo r the radioactive waste treatment system to resolve seismic Class I/II interface issues discussed in RAI 2.1-2A(3) of SER Section 2.1. By
 
letters dated January 31, 2005, and February 28, 2005, the applicant submitted the results of its
 
review of the seismic Class I qualification documentation to identify the NSR piping, supports/equivalent anchors, or other components that are within the scope of license renewal
 
in accordance with the requirements of 10 CFR 54.4(a)(2) for the (a)(2) cases where NSR
 
piping or components are directly connected to SR piping or components. In its February 28, 2005 letter, enclosure 2, "Mechanical Systems," the applicant stated that additional piping and 2-113 components were added to the scope in the cleanup decant pump room in the radwaste building. The component types do not differ from those listed in LRA Table 2.3.3.25; therefore, no changes to the radioactive waste treatment system portion of the LRA are required. In its
 
response, the applicant explained that notes had been added to the radioactive waste treatment
 
drawing to clarify that embedded piping is in scope for anchorage when attached to
 
non-embedded in-scope piping and all the piping between the embedded piping and in-scope
 
non-embedded piping is within the scope of license renewal.
The staff reviewed the results of the applicant's evaluation of NSR piping segments that support secondary containment in response to RAI 2.1-2A(1) and (2), and the results of the applicant's evaluation of seismic Class I piping boundaries in its response to RAI 2.1-2A(3). The staff found
 
the expanded scope of components to be acceptable, because the applicant had adequately
 
included NSR components with the configurations that meet the scoping criterion of
 
10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR
 
piping or components.
2.3.3.25.3  Conclusion
 
The staff reviewed the LRA and RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff performed a review to determine whether any components that
 
should be subject to an AMR had not been identified by the applicant. No omissions were
 
identified. On the basis of its review, the staff concluded that there is reasonable assurance that
 
the applicant had adequately identified the radioactive waste treatment system components that
 
are within the scope of license renewal, as required by 10 CFR 54.4(a), and the radioactive
 
waste treatment system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.26  Fuel Pool Cooling and Cleanup System 2.3.3.26.1  Summary of Technical Information in the Application In LRA Section 2.3.3.26, the applicant described the FPC system. The FPC system removes residual heat from the fuel assemblies and maintains the fuel pool water within the specified
 
temperature limits. The system minimizes corrosion product buildup and controls water clarity in
 
the fuel pool so that the fuel assemblies can be efficiently handled underwater. In addition, the
 
FPC system minimizes fission product concentration in the fuel pool water. The system is in
 
normal operation and additional provisions can be made to prevent siphoning of the fuel pool. A
 
cross-connection exists with the RHR system
; the RHR system can provide supplemental cooling, if needed.
The FPC system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the FPC system could prevent the satisfactory
 
accomplishment of an SR function. In addition, the FPC system performs functions that support
 
fire protection.
2-114 The intended functions within the scope of license renewal include the following:
* provides a secondary containment boundary
* provides for pressure boundary integrity at the RHR/FPC interface
* prevents inadvertent siphoning of the spent fuel pool
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.26, the applicant identified the following FPC system component types that are within the scope of license renewal and subject to an AMR: bolting, expansion joint, fittings, heat exchangers, piping, pumps, restricting orifice, tanks, tubing, and valves.
2.3.3.26.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.26 and UFSAR Sections 4.8, 5.3, 10.5, 10.17, and 10.22 using the evaluation methodology described in SER Section 2.3. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER Section 2.1 related to NSR piping segments that support secondary containment, the applicant
 
expanded the system boundaries for the fuel pool cooling and cleanup system. By letter dated May 31, 2005, the applicant submitted the results of its review of piping, supports, and other
 
components outside secondary containment required to maintain the structural integrity of
 
secondary containment that are within the scope of license renewal in accordance with the
 
requirements of 10 CFR 54.4(a)(2) for secondary containment qualification. In the enclosure to
 
its letter dated May 31, 2005, the applicant stated that additional piping had been added to
 
scope. However, the component type does not differ from those listed in LRA Table 2.3.3.26;
 
therefore, no changes to the fuel pool cooling and cleanup system portion of the LRA are
 
required.The applicant also expanded the system boundaries for the FPC system to resolve the seismic Class I/II interface issues discussed in RAI 2.1-2A(3) of SER Section 2.1. By letters dated
 
January 31, 2005, and February 28, 2005, the applicant submitted the results of its review of the
 
seismic Class I qualification documentation to identify the NSR piping, supports/equivalent
 
anchors, or other qualification documentation to identify the NSR piping, supports/equivalent
 
anchors, or other components that are within the scope of license renewal in accordance with
 
the requirements of 10 CFR 54.4(a)(2) for the (a)(2) cases in which NSR piping or components
 
are directly connected to SR piping or components. In the February 28, 2005 letter, enclosure 2, "Mechanical Systems," the applicant stated that additional piping and components had been
 
added to the scope of the FPC system. However, the component types do not differ from those 2-115 listed in LRA Table 2.3.3.26; therefore, no changes to the FPC system portion of the LRA are required.The staff reviewed the results of the applicant's evaluation of NSR piping segments that support secondary containment in response to RAI 2.1-2A(1) and (2), and the results of the applicant's
 
evaluation of seismic Class I piping boundaries in its response to RAI 2.1-2A(3). The staff found
 
the expanded scope of components to be acceptable, because the applicant had adequately
 
included NSR components with the configurations that meet the scoping criterion of
 
10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR
 
piping or components.
2.3.3.26.3  Conclusion
 
The staff reviewed the LRA and RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff performed a review to determine whether any components that
 
should be subject to an AMR had not been identified by the applicant. No omissions were
 
identified. On the basis of its review, the staff concluded that there is reasonable assurance that
 
the applicant had adequately identified the FPC system components that are within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and the FPC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.27  Fuel Handling and Storage System 2.3.3.27.1  Summary of Technical Information in the Application In LRA Section 2.3.3.27, the applicant described the fuel handling and storage system. Each unit is provided with a dry, new fuel storage vault. The new fuel storage racks provide a location in the vaults where new fuel can be stored. The racks are designed to preclude criticality even if
 
the new fuel storage vault is flooded. Each reactor also has a spent fuel storage pool. A transfer
 
canal is provided to join the pools for Units 1 and 2. The spent fuel storage racks provide a
 
location where spent fuel, received from the reactor vessel, can be stored at the bottom of each
 
fuel pool. The racks are full length, top entry, and are designed to maintain the spent fuel in a
 
spatial geometry that precludes the possibility of criticality. The racks are comprised of
 
staggered, stainless-steel container tubes. Each tube wall has a core of Boral sandwiched
 
within stainless steel. Servicing equipment is provided to facilitate refueling, fuel inspection, and
 
fuel maintenance.
The fuel handling and storage system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the fuel handling and
 
storage system could prevent the satisfac tory accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides NSR components that ensure t he satisfactory performance of SR components
* provides structural support In LRA Table 2.3.3.27, the applicant identified the following fuel handling and storage system component types that are within the scope of license renewal and subject to an AMR: bolting 2-116 and fasteners, fuel preparation machines, and the refueling platform (including the assembly, rails, and main fuel grapple).
2.3.3.27.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.27 and UFSAR Sections 10.2, 10.3, 10.4, and 10.5 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in
 
accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.27, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning
 
the specific issue to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAI and the applicant's related response.
In RAI 2.3.3.27-1, the staff stated that LRA Section 2.3.3.27 states that the portions of the fuel handling and storage system that contain components subject to an AMR are the fuel
 
preparation machines, refueling platform (assembly, rails, and the main fuel grapple), and the
 
bolting and fasteners associated with the refueling platform and fuel preparation machines. LRA
 
Table 2.3.3.27 lists components associated with the fuel handling and storage systems that are
 
subject to an AMR. UFSAR Section 10.4 (in Table 10.4-1, "Tools and Servicing Equipment")
 
lists fuel servicing equipment, including general purpose grapple, channel transfer grapple, fuel
 
inspection fixture, and new fuel inspection stand, but none of these are referenced in LRA
 
Section 2.3.3.27. In reviewing LRA Section 2.3.3.27, the staff also found that no drawings are
 
provided for this system. There is insufficient information for the staff to determine whether
 
these components are within the scope of license renewal and subject to an AMR. Therefore, the staff requested that the applicant identify which of these components are within the scope of
 
license renewal and subject to an AMR.
In its response, by letter dated October 19, 2004, the applicant stated the general purpose grapple, channel transfer grapple, and fuel inspection fixture are within the scope of license
 
renewal; however, an AMR is not required for thes e components since they are active (i.e., they change configuration). The applicant also stated that the new fuel inspection stand is not SR
 
and does not meet the criterion in 10 CFR 54.4(a)(1). The new fuel inspection stand is also not
 
required for any of the 10 CFR 54.4(a)(3) regulated events. The applicant further stated that the
 
new fuel inspection stand failure would not prevent the accomplishment of an SR intended
 
function of an SR component and does not meet the requirements of 10 CFR 54.4(a)(2).
Based on its review, the staff found the applicant's response to RAI 2.3.3.27-1 acceptable. The applicant had adequately clarifies that the components in question are either active or do not 2-117 meet any of the requirements of 10 CFR 54.4(a). Therefore, the staff's concern described in RAI 2.3.3.27-1 is resolved.
2.3.3.27.3  Conclusion
 
The staff reviewed the LRA and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the fuel handling and storage
 
system components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the fuel handling and storage system components that are subject to an
 
AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.28  Diesel Generator System 2.3.3.28.1  Summary of Technical Information in the Application In LRA Section 2.3.3.28, the applicant described the diesel generator (DG) system. The DG system is a plant-shared system that consis ts of four independent DG units, coupled as an alternate independent source of power to four 4160 V shared shutdown boards for
 
Units 1 and 2. There are four additional DG units that provide an alternate independent source
 
of power to four Unit 3 4160 V shutdown boards. The DG system provides an alternate source of power for the ECCS and the safe shutdow n systems when the normal power supplies are unavailable. The DGs are normally in standby and can start automatically, when required.
The DG system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the DG system could prevent the satisfactory
 
accomplishment of an SR function. In addition, the DG system performs functions that support fire protection, EQ, and SBO.
The intended functions within the scope of license renewal include the following:
* starts standby AC power source for the 4kV system
* provides power to the 4kV system upon DG availability and loss of offsite power
* provides DG power to diesel fuel transfer pumps
* provides debris protection
* provides for heat transfer
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.28, the applicant identified the following DG system component types that are within the scope of license renewal and subject to an AMR: bolting, ductwork, fan housings, fittings, flexible connectors, heat exchangers, heaters, piping, pumps, silencer, strainers, tanks, tubing, valves, and RCPB valves.
2-118 2.3.3.28.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.28 and UFSAR, Sections 7.4, 7.18, 8.4, 8.5, 8.10, and F.7.9 using the evaluation methodology described in SER Section 2.3. The staff conducted its
 
review in accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.28, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning
 
the specific issue to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAI and the applicant's response.
In RAI 2.3.3.28-1, the staff identified two components (governor and drain pan) in the DG lube oil subsystem that are not subject to an AMR; however, the piping into and out of these
 
components is subject to an AMR. Therefore, the staff requested that the applicant justify the
 
exclusion of the subject components from within the scope of license renewal and an AMR.
In its response, by letter dated October 19, 2004, the applicant stated that the governor is a controller that is an active component based on components listed in Appendix B of NEI 95-10, Revision 3, and does not require an AMR. With regard to the drain pan, the applicant stated that
 
the drain pan is not within the scope of license renewal since it does not perform a
 
10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3) function. The drain pan would also not be in scope for
 
10 CFR 54.4(a)(2) since it is not normally fluid-filled and does not present a spray hazard.
 
During a teleconference on May 11, 2005, the applicant clarified that the drain pan is attached
 
to the DG frame and is not in any way attached to or functionally associated with the lube oil
 
system. Its only purpose is to collect any spillage during maintenance when replacing the oil
 
filter. Additionally, the piping, valves, and fittings attached to the drain pan, as shown in the
 
license renewal drawings 0-47E861-5-LR th rough 0-47E861-8-LR and 3-47E861-5-LR through 3-47E861-8-LR, were inadvertently colored as being within the scope of license renewal and
 
subject to an AMR. These drawings have been revised to reflect that these valves, piping, and
 
fittings are not within the scope of license renewal and not subject to an AMR. The changes will
 
be incorporated in the next annual update.
Based on its review, the staff found the applicant's response to RAI 2.3.3.28-1 acceptable. It justified the exclusion of the governor from an AMR. The applicant also clarifies that the piping, valves, and fittings attached to the drain pan had been colored inadvertently and that the drain
 
pan does not perform a license renewal intended function per 10 CFR 54.4. Therefore, the
 
staff's concern described in RAI 2.3.3.28-1 is resolved.
2-119 2.3.3.28.3  Conclusion The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI response described above to determine whether any SSCs that should be within the scope of license
 
renewal had not been identified by the applicant. No omissions were identified. In addition, the
 
staff performed a review to determine whether any components that should be subject to an
 
AMR had not been identified by the applicant. No omissions were identified. On the basis of its
 
review, the staff concluded that there is reasonable assurance that the applicant had adequately
 
identified the DG system components that are within the scope of license renewal, as required
 
by 10 CFR 54.4(a), and the DG system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.29  Control Rod Drive System 2.3.3.29.1  Summary of Technical Information in the Application In LRA Section 2.3.3.29, the applicant described the CRD system. The CRD system provides reactivity control by allowing positioning of the control rods at a controlled rate during normal
 
operation; providing scram and diverse scram functions to ensure rapid shutdown, when required; limiting the rod drop rate to minimize the consequences of a rod drop accident; and
 
limiting a rod ejection accident.
From the hydraulic control units, the portions of the system that are subject to an AMR extend to, and from, each control rod housing. From the hydraulic control units, the portions of the
 
system that are subject to an AMR extend to, and then include, the scram discharge volume
 
and associated components. From the hydraulic cont rol units, portions of the system subject to an AMR extend to an interconnection with the RWCU system. The CRDs themselves are
 
short-lived components and, hence, are not subject to an AMR; however, the CRD housing
 
support is subject to an AMR and is included in the component supports commodity group, which is discussed in another section of this SER.
The CRD system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the CRD system could prevent the satisfactory
 
accomplishment of an SR function. In addition, the CRD system performs functions that support
 
fire protection, EQ, ATWS, and SBO.
The intended functions within the scope of license renewal include the following:
* provides primary and secondary containment boundaries
* provides RCPB
* provides housing support to keep the rods in place
* limits the rod drop rate to less than 3.11 feet per second
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.29, the applicant identified the following CRD system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings, 2-120 heat exchangers, piping, RCPB piping, pumps, restricting orifice, rupture disk, strainers, RCPB strainers, tanks, tubing, valves, and RCPB valves.
2.3.3.29.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.29 and UFSAR Sections 3.4, 3.5, 3.7, 5.2.3, 5.3, 7.7, 7.19, and F.7.12 using the evaluation methodology described in SER Section 2.3. The staff
 
conducted its review in accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.29.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In
 
addition, the staff performed a review to determine whether any components that should be
 
subject to an AMR had not been identified by the applicant. No omissions were identified. On
 
the basis of its review, the staff concluded that there is reasonable assurance that the applicant
 
had adequately identified the CRD system components that are within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and the CRD system components that are subject to
 
an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.30  Diesel Generator Starting Air System 2.3.3.30.1  Summary of Technical Information in the Application In LRA Section 2.3.3.30, the applicant described the DG starting air system. The DG starting air system starts the DGs when required. Each DG has an independent starting air system. Each system has two independent subsystems that are both capable of starting their respective DG.
 
Each subsystem consists of an air compressor with associated filters and coolers, and a bank of
 
air receivers. The air compressors operate automatically to maintain the receivers in a
 
pressurized state. The DG starting air system is located in the DG buildings.
The DG starting air system contains SR components that are relied upon to remain functional during, and following, DBEs. In addition, the DG starting air system performs functions that
 
support fire protection and SBO.
The intended functions within the scope of license renewal include the following:
* provides diesel starting air to the DG system
* provides debris protection
* provides mechanical closure
* provides pressure boundary 2-121
* provides structural support In LRA Table 2.3.3.30, the applicant identified the following DG starting air system component types that are within the scope of license renewal and subject to an AMR: bolting, diesel air start
 
motor, fittings, flexible connectors, piping, strainers, tanks, tubing, and valves.
2.3.3.30.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.30 and UFSAR Section 8.5.3.3 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In order to resolve the seismic Class I/II interface issues discussed in RAI 2.1-2A(3) of SER Section 2.1, the applicant expanded the system boundaries for the diesel generator starting air
 
system. By letters dated January 31, 2005, and February 28, 2005, the applicant submitted the
 
results of its review of the seismic Class I qualification documentation to identify the NSR piping, supports/equivalent anchors, or other components that are within the scope of license renewal
 
in accordance with the requirements of 10 CFR 54.4(a)(2) for the cases where NSR piping or
 
components are directly connected to SR piping or components. In the February 28, 2005 letter, enclosure 2, "Mechanical Systems," the applicant stated that additional piping and components
 
had been added to scope in association with the outlet filter of the air dryer skid, which is
 
credited as an anchor in the seismic analysis. However, the component types do not differ from
 
those listed in LRA Table 2.3.3.30; therefore, no changes to the diesel generator starting air
 
system portion of the LRA are required. The staff reviewed applicant's submittals and found the
 
expanded scope of components to be acceptable, because the applicant had adequately
 
included NSR components with the configurations that meet the scoping criterion of
 
10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR
 
piping or components.
2.3.3.30.3  Conclusion
 
The staff reviewed the LRA and RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff performed a review to determine whether any components that
 
should be subject to an AMR had not been identified by the applicant. No omissions were
 
identified. On the basis of its review, the staff concluded that there is reasonable assurance that
 
the applicant had adequately identified the DG starting air system components that are within
 
the scope of license renewal, as required by 10 CFR 54.4(a), and the DG starting air system
 
components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1222.3.3.31  Radiation Monitoring System 2.3.3.31.1  Summary of Technical Information in the Application In LRA Section 2.3.3.31, the applicant described the radiation monitoring system. The radiation monitoring system consists of a number of radi ation monitors and monitoring systems that are provided on process liquid and gas lines that may serve as discharge routes for radioactive materials.
The radiation monitoring system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the radiation monitoring
 
system could prevent the satisfactory accomp lishment of an SR function. In addition, the radiation monitoring system performs functions that support EQ.
The intended functions within the scope of license renewal include the following:
* provides primary and secondary containment boundaries
* provides system pressure boundary integrity (with all mechanical joints and components associated with the offline liquid monitors) to RHRSW system cooling water for RHR
 
system heat exchangers
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.31, the applicant identified the following radiation monitoring system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, flex hose, piping, pumps, strainers, traps, tubing, and valves.
2.3.3.31.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.31 and UFSAR Sections 5.2.3, 7.12, 7.13, 7.14, 7.15, and F.7.5 using the evaluation methodology described in SER Section 2.3. The staff
 
conducted its review in accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.31, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning
 
the specific issue to determine whether the applicant had properly applied the scoping criteria of 2-123 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff's RAI and the applicant's response.
In RAI 2.3.3.31-1, the staff identified the following monitors as being subject to an AMR:
* gas monitors
* RHR heat exchanger A & C service water discharge radiation monitor
* RHR heat exchanger B & D service water discharge radiation monitor
* raw cooling water radiation monitor
* reactor building closed cooling water radiation monitor The monitor housing performs a pressure boundary intended function; however, the housing is not listed in LRA Table 2.3.3.31 as a component type subject to an AMR. LRA Section 2.3.5
 
does not include housing as a part of any component group. Therefore, the staff requested that
 
the applicant clarify whether housings are considered to be part of a component group already
 
listed in LRA Table 2.3.3.31.
In its response, by letter dated October 19, 2004, the applicant stated that the radiation monitor sample chambers (housings) are included as part of the component type "fittings" in LRA
 
Table 2.3.3.31.
Based on its review, the staff found the applicant's response to RAI 2.3.3.31-1 acceptable. It clarifies that the monitor housings are already included in LRA Table 2.3.3.31 in the component
 
type "fittings" as being subject to an AMR. Therefore, the staff's concern described in
 
RAI 2.3.3.31-1 is resolved.
In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER Section 2.1 related to NSR piping segments that support secondary containment, the applicant expanded the system boundaries for the radiation monitoring system. By letter dated May 31, 2005, the applicant submitted the results of its review of piping, supports, and other components outside secondary containment required to maintain the structural integrity of secondary containment that are within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2) for secondary containment qualification. In the enclosure to its letter dated May 31, 2005, the applicant stated that additional components associated with radiation monitor RM 90-250 had been added to scope. However, the component types do not differ from those listed in LRA Table 2.3.3.31; therefore, no changes to the radiation monitoring system portion of the LRA are required. The staff reviewed applicant's submittal and found the expanded scope of components to be acceptable, because the applicant had adequately included NSR components with the configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are dire ctly connected to SR piping or components.
2.3.3.31.3  Conclusion
 
The staff reviewed the LRA and RAI responses described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the
 
applicant. No omissions were identified. In addition, the staff performed a review to determine
 
whether any components that should be subject to an AMR had not been identified by the
 
applicant. No omissions were identified. On the basis of its review, the staff concluded that there
 
is reasonable assurance that the applicant had adequately identified the radiation monitoring 2-124 system components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the radiation monitoring system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.32  Neutron Monitoring System 2.3.3.32.1  Summary of Technical Information in the Application In LRA Section 2.3.3.32, the applicant described the neutron monitoring system. The neutron monitoring system detects conditions in the core that threaten the overall integrity of the fuel
 
barrier due to excessive power generation. The sy stem also provides signals to the reactor protection system so that the release of radioactive material from the fuel barrier is limited. In
 
addition, the neutron monitoring system provi des information for the efficient, expeditious operation and control of the reactor. Conditions that could lead to local fuel damage are
 
detected by the system and used to prevent such damage.
The neutron monitoring system contains SR components that are relied upon to remain functional during, and following, DBEs.
The intended functions within the scope of license renewal include the following:
* provides RCPB
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.3.32, the applicant identified the following neutron monitoring system component types that are within the scope of license renewal and subject to an AMR: bolting
 
and RCPB fittings.
2.3.3.32.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.32 and the UFSAR Sections 3.7 and 7.5 using the evaluation methodology described in SER Section 2.3. The staff conducted its review
 
in accordance with the guidance described in the NRC's SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omittedfrom the scope of license renewal any components with intended functions delineated under10 CFR 54.4(a). The staff then reviewed those com ponents that the applicant had identified as being within the scope of license renewal to verify that the applicant had not omitted any
 
passive and long-lived components that should be subject to an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.32, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated October 8, 2004, the staff issued an RAI concerning
 
the specific issues to determine whether the applicant had properly applied the scoping criteria 2-125 of 10 CFR 54.4 (a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff's RAIs and the applicant's related responses.
In RAI 2.3.3.32-1, the staff stated that LRA Section 2.3.3.32 states that the average power range monitor subsystem averages the local power range monitor subsystem signals to provide
 
an overall indication of reactor power for control and trip functions. A subsystem of the average
 
power range monitor subsystem, the oscillation power range monitor (OPRM) ensures reactor
 
operation in a stable thermal-hydraulic region.
The rod block monitor (RBM) receives input from local power range monitors close to a control rod to prevent fuel damage in the event of a rod
 
withdrawal error. Furthermore, it was stated in the LRA that the portions of the neutron
 
monitoring system that contain components subjec t to an AMR are only those that form part of the reactor coolant pressure boundary. The staff believes that in addition to the portions that are
 
pressure boundary, OPRM and its functions, as described above, are passive and SR; and
 
hence meet the criteria delineated in 10 CFR 54.4(a)(1) and 10 CFR 54.21(a)(1). Therefore, unless the OPRM is subject to replacement based on a "qualified life" or "specified time period,"
or degradation of its ability to perform its intended functions due to aging is readily monitorable, the component should be within the scope requiring aging management. Therefore, the staff
 
requested the applicant to provide a justification for why these components are not within the
 
scope of license renewal.
The staff also requested the applicant to provide the basis for excluding other neutron monitoring subsystems in BFN (except portions that perform pressure boundary function) from
 
within the scope of license renewal.
In its response, by letter dated November 3, 2004, the applicant stated that LRA Section 2.3 lists the mechanical scoping and screening results. The only mechanical SR passive intended
 
function of the neutron monitoring system is reactor coolant pressure boundary. The scoping
 
and screening results for the electrical com ponents of the neutron monitoring system are addressed in LRA Section 2.5. The applicant further stated that the "spaces approach" was
 
utilized for scoping of electrical components, which does not exclude any electrical components
 
from the scope of license renewal. The applicant included the subject components and its
 
intended functions within the scope requiring an AMR.
Based on its review, the staff found the applicant's response to RAI 2.3.3.32-1 acceptable. The applicant included the subject components and their intended functions within the scope
 
requiring an AMR. Therefore, the staff's concern described in RAI 2.3.3.32-1 is resolved.
2.3.3.32.3  Conclusion
 
The staff reviewed the LRA and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the neutron monitoring
 
system components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the neutron monitoring system components that are subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2-126 2.3.3.33  Traversing In-Core Probe System 2.3.3.33.1  Summary of Technical Information in the Application In LRA Section 2.3.3.33, the applicant described the traversing in-core probe (TIP) system. The TIP system provides a signal proportional to the axial flux distribution at selected core locations where the local power range monitor detector assemblies are located. This signal
 
allows reliable calibration of the power range monitor amplifiers. The TIP drive mechanism uses
 
a detector that is attached to a flexible drive cable, which is driven from outside the primary containment by a gear box assembly. The flex ible cable is contained by guide tubes that penetrate the reactor vessel and continue into the reactor core through a dry tube in a local
 
power range monitor assembly. Provisions are made for automatic retraction of the detection and isolation of the primary containment penetration, when required.
The TIP system contains SR components that are relied upon to remain functional during, and following, DBEs.
The intended functions within the scope of license renewal include the following:
* provides primary containment boundary isolation and integrity (active isolation function is not required)
* provides pressure boundary In LRA Table 2.3.3.33, the applicant identified the following TIP system component types that are within the scope of license renewal and subject to an AMR: fittings, tubing, and valves.
2.3.3.33.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.33 and the UFSAR 5.2.3, 7.3, and 7.5 using the evaluation methodology described in SER Section 2.3. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omittedfrom the scope of license renewal any components with intended functions deli neated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had identified as
 
being within the scope of license renewal to verify that the applicant had not omitted any
 
passive and long-lived components that should be subject to an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
2.3.3.33.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In
 
addition, the staff performed a review to determine whether any components that should be
 
subject to an AMR had not been identified by the applicant. No omissions were identified. On
 
the basis of its review, the staff concluded that there is reasonable assurance that the applicant
 
had adequately identified the TIP system components that are within the scope of license 2-127 renewal, as required by 10 CFR 54.4(a), and the TIP system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.34  Cranes System 2.3.3.34.1  Summary of Technical Information in the Application In LRA Section 2.3.3.34, the applicant described the cranes system. The cranes system includes numerous plant load-handling devices that are used for maintenance of selected plant
 
components.
The portions of the cranes system containing components subject to an AMR include the structural portions of the cranes in structures with SR components.
The failure of SR SSCs in the cranes system c ould prevent the satisfactory accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides NSR components that ensure t he satisfactory performance of SR components
* provides structural support In LRA Table 2.3.3.34, the applicant identified the following cranes system component types that are within the scope of license renewal and subject to an AMR: bolting and fasteners, monorails, rail, rail clips, and structural girders.
2.3.3.34.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.34 and UFSAR Section 12.2 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.34, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning
 
the specific issue to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAI and the applicant's related response.
In RAI 2.3.3.34-1, the staff stated that in reviewing the cranes system described in LRA Section 2.3.3.34, the staff found that no drawings had been provided for this system. There is 2-128 insufficient information for the staff to determine which cranes are within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). In addition, mobile A-frames mentioned in LRA
 
Section 2.1.2.2 are not mentioned in LRA Section 2.3.3.34 or in the UFSAR. Therefore, the staff
 
requested that the applicant identify which cranes are within the scope of license renewal and
 
subject to an AMR, and whether the mobile A-frames are within the scope of license renewal.
In its response, by letter dated October 19, 2004, the applicant stated that the buildings that contain NSR cranes and monorails that could pr event SR SSCs from performing their intended function(s) are the reactor building, primary containment, DG building, intake pumping station, and the reinforced concrete chimney. All cranes and monorails in these buildings are within the
 
scope of license renewal. The applicant further stated that the mobile A-frames are cranes on
 
wheels. These A-frames are within the scope of license renewal since they could be used in an
 
SR building, they are also subject to an AMR.
Based on its review, the staff found the applicant's response to RAI 2.3.3.34-1 acceptable. It identifies the buildings containing the cranes that are within the scope of license renewal to
 
meet the 10 CFR 54.4(a)(2) requirements, and it confirms that the mobile A-frames are within
 
the scope of license renewal and subject to an AMR. Therefore, the staff's concern described in
 
RAI 2.3.3.34-1 is resolved.
2.3.3.34.3  Conclusion
 
The staff reviewed the LRA and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the cranes system
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the cranes system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4  Steam and Power Conversion Systems In LRA Section 2.3.4, the applicant identified the structures and components of the steam and power conversion systems that are s ubject to an AMR for license renewal.
The applicant described the supporting structures and components of the steam and power conversion systems in the following sections of the LRA:
* 2.3.4.1main steam system
* 2.3.4.2condensate and demineralized water system
* 2.3.4.3feedwater system
* 2.3.4.4heater drains and vents system
* 2.3.4.5turbine drains and miscellaneous piping system
* 2.3.4.6condenser circulating water system
* 2.3.4.7gland seal water system The corresponding sections of this SER (2.3.4.1 - 2.3.4.7) present the staff's review findings with respect to the steam and power conversion systems for BFN.
2-1292.3.4.1  Main Steam System 2.3.4.1.1  Summary of Technical Information in the Application In LRA Section 2.3.4.1, the applicant described the MS system. Each unit has its own MS system that consists of four MS lines that transfer steam from the reactor vessel to the various
 
steam loads in the turbine building during normal plant operation. Two MSIVs are provided in
 
each steam line to isolate the RCPB and the primary containment. A flow restrictor allows for
 
the measurement of steam flow and also limits t he steam flow rate in the event of a downstream steam line break. MSRVs are provided for overpressure protection and for depressurization
 
following small-break LOCAs. Main steam co mponents downstream of the MSIVs are credited in analyses for MSIV alternate leakage treatment.
The MS system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the MS system could prevent the satisfactory
 
accomplishment of an SR function. In addition, the MS system performs functions that support
 
fire protection, EQ, and SBO.
The intended functions within the scope of license renewal include the following:
* provides for opening of safety relief valves (SRVs) during high reactor pressure to provide reactor pressure vessel relief
* provides MS line flow restrictors to passively limit the mass flow rate of the coolant being ejected following a steam-line break until MSIV closure occurs
* provides RCPB
* provides primary and secondary containment boundaries
* provides steam for the HPCI turbine
* establishes an MSIV leakage pathway to the condenser
* provides steam for the RCIC turbine
* restricts flow
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.4.1, the applicant identified the following MS system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings, piping, RCPB piping, restricting orifice, RCPB restricting orifice, strainers, tubing, valves, and
 
RCPB valves.
2.3.4.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.1 and UFSAR Sections 3.7, 4.1, 4.4, 4.5, 4.6, 4.11, 5.2.3, 5.3, 6.4.2, 7.2, 7.3, 7.4, 7.10, 7.11, 7.12, 7.18, 11.2, and 11.5 using the evaluation methodology 2-130 described in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.4.1, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated October 8, 2004, the staff issued RAIs concerning the
 
specific issues to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAIs and the applicant's related responses.
In RAI F 2.3.4.1-1, the staff stated that 0roviding a leakage pathway from the MSIVs to the main condenser is one of the intended functions of the main steam system. Regarding Unit 1, LRA
 
Appendix F states that the segment of the main steam piping from the outermost isolation valve
 
up to the turbine stop valve, the bypass/drain piping to the main condenser and the main
 
condenser itself is being evaluated and modified as required to ensure that structural integrity
 
during and after a safe shutdown earthquake (SSE) is maintained. The staff identified that
 
portions of the main steam system (from the turbine building on) are not shown on license
 
renewal drawing 1-47E801-1-LR as being subject to an AMR. However, similar segments of
 
piping are shown as being subject to an AMR on license renewal drawings 2-47E801-1-LR and
 
3-47E801-1-LR. It is not clear to the staff, on the basis of a review of the drawings and the
 
information provided in LRA Sections 2.1 and F.1 of Appendix F, why the sections of piping on
 
license renewal drawing 1-47E801-1-LR are not subject to an AMR. Therefore, the staff
 
requested that the applicant justify the exclusion of the piping sections in question from being
 
within the scope of license renewal and from being subject to an AMR.
In its response, by letter dated October 25, 2004, the applicant stated that license renewal drawings depict components subject to an AMR based on the units' CLB. As documented in
 
Appendix F.1 of the LRA, the Unit 1 CLB for MSIV leakage does not incorporate an alternate
 
leakage treatment pathway utilizing main steam piping and the main condenser because
 
currently this modification is not physically impl emented for Unit 1 to match Units 2 and 3 in their configuration.
The LRA was structured to reflect the configuration and CLB of all three units. Scoping and screening was done based on the CLB and configuration of all three units. The differences
 
between the units that are relevant to the application and will be resolved prior to Unit 1 restart
 
are listed in LRA Appendix F.
In addition, by letter dated January 31, 2005, the applicant provided additional/supplementary information, stating that as each activity identified in Appendix F is completed, the
 
corresponding bold-bordered text in the LRA will apply to Unit 1. The applicant stated in its
 
response that the only change to the application will be to remove the bolded border. No 2-131 changes are required for scoping and screening, or AMR results, or TLAAs. However, in some cases, boundary drawings would change to reflect the bold-bordered text. The applicant
 
committed to perform a secondary application review after the modification is implemented in
 
the plant for Unit 1, and license renewal drawing 1-47E801-1-LR will be revised and submitted
 
during the annual update. This will assure that the design changes that implement this
 
modification do not modify or change the basis of how these components were initially scoped and screened.
Based on its review, the staff found the applicant's response to RAI F 2.3.4.1-1 acceptable. The Unit 1 CLB for MSIV leakage does not incorporate an alternate leakage treatment pathway
 
utilizing the main steam piping and main condenser and, therefore, this portion of piping is not
 
subject to an AMR at this time. Upon completion of the modifications discussed in LRA
 
Appendix F and the January 31, 2005, letter, the CLB for Unit 1 will be the same as Units 2 and
: 3. The review of LRA Appendix F regarding Unit 1 restart will be addressed in SER
 
Section 2.6.1.1. Therefore, the staff's concern described in RAI F 2.3.4.1-1 is resolved.
In RAI F 2.3.4.1-2, the staff stated that license renewal drawings 2-47E801-2, 2-47E807-2, 3-47E801-2, and 3-47E807-2 highlight certain main steam system components for Units 2 and 3
 
associated with the reactor feed pump turbine drivers, the steam air ejector subsystem, and the
 
steam seal regulator subsystem as being within the scope of license renewal and subject to an
 
AMR. The corresponding components for Unit 1 should likewise be subject to an AMR.
 
However, the drawings that show these components, such as license renewal drawings
 
1-47E801-2 (shown as a continuation line on drawing 1-47E801-1) and 2-47E807-2 and
 
3-47E807-2 (the corresponding drawings for Unit 1) are not provided. As a result, the staff was
 
unable to determine if all of the aforementioned Unit 1 components, that are within the scope of
 
license renewal and subject to an AMR for Units 2 and 3 were identified. Therefore, the staff
 
requested that the applicant provide license renewal drawing 1-47E801-2 and the Unit 1
 
drawing that corresponds to drawings 2-47E807-2 and 3-47E807-2.
In its response, by letter dated October 25, 2004, the applicant stated that the license renewal drawings depict components subject to an AMR based on the units' CLB. As documented in
 
LRA Appendix F.1, the Unit 1 CLB for MSIV leakage does not incorporate an alternate leakage
 
treatment pathway utilizing the main steam piping and main condenser. Appendix F.1 identifies
 
the activities required to be completed in order to make the subject licensing basis applicable to
 
Unit 1. Since activities required by LRA Appendix F.1 are not complete, the piping/components
 
of the subject system are not subject to an AMR at this time.
The applicant further stated that at this time the modification to implement this change into the plant for Unit 1 has not been implemented. Therefore, the piping for Unit 1 does not perform the
 
alternate leakage pathway function. The applicant further stated that once the modification has
 
been implemented in the plant, Unit 1 license renewal drawings addressed in the RAI will be
 
added to the application and submitted during the annual update with the same components on
 
Unit 1 requiring an AMR as those shown on the Unit 2 and Unit 3 license renewal drawings.
Based on its review, the staff found the applicant's response to RAI 2.3.4.1-2 acceptable. It clarifies that the Unit 1 CLB for MSIV leakage does not incorporate an alternate leakage
 
treatment pathway utilizing main steam piping and the main condenser since the activities (identified in LRA Appendix F.1) required to make the Unit 1 CLB for MSIV leakage the same as
 
that for Units 2 and 3 is not subject to an AMR at this time. The applicant also clarifies that once 2-132 the modification is implemented, Unit 1 license renewal drawings will be submitted with the same components on Unit 1 that require an AMR as those shown on the Unit 2 and Unit 3
 
license renewal drawings. The review of LRA Appendix F regarding Unit 1 restart will be
 
addressed in SER Section 2.6.1.1. Therefore, the staff's concern described in RAI 2.3.4.1-2 is
 
resolved.In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER Section 2.1 related to NSR piping segments which support secondary containment, the applicant expanded the system boundaries for the ma in steam system. By letter dated May 31, 2005, the applicant submitted the results of its review of piping, supports, and other components outside secondary containment required to maintain the structural integrity of secondary containment that are within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2) for secondary containment qualification. In the enclosure to its letter dated May 31, 2005, the applicant stated that additional piping, fittings, and valves had been added to scope. However, the component types do not differ from those listed in LRA Table 2.3.4.1; therefore, no changes to the main steam system portion of the LRA are required.
The staff reviewed the NSR piping segments and found the expanded scope of components to be acceptable, because the applicant had adequately included NSR components with the configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR piping or components 2.3.4.1.3  Conclusion
 
The staff reviewed the LRA, the accompanying scoping boundary drawing, and RAI responses described above to determine whether any SSCs that should be within the scope of license
 
renewal had not been identified by the applicant. No omissions were identified. In addition, the
 
staff performed a review to determine whether any components that should be subject to an
 
AMR had not been identified by the applicant. No omissions were identified. On the basis of its
 
review, the staff concluded that there is reasonable assurance that the applicant had adequately
 
identified the MS system components that are within the scope of license renewal, as required
 
by 10 CFR 54.4(a), and the MS system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.4.2  Condensate and Demineralized Water System 2.3.4.2.1  Summary of Technical Information in the Application In LRA Section 2.3.4.2, the applicant described the condensate and demineralized water system. The main system is the condensate syst em which provides treated water at required flow rates for the FW system during normal pl ant operation. The system is unique to each unit and the individual systems do not share components with one another. The turbine-generator
 
condenser provides a heat sink for the closed-loop steam cycle and removes non-condensable
 
gases. In addition, impurities are removed by a full-flow demineralizer system. The system also cools the steam jet air ejector intercondenser, the off-gas condenser, and the steam packing
 
exhauster condenser. The condenser is credited in analyses for MSIV alternate leakage
 
treatment.
2-133 Subsystems of the condensate system are the condensate storage and transfer system, for radioactive high purity water, and the demineralized water system, for non-radioactive high
 
purity water. The tanks also provide a surge volume for flow testing of HPCI, RCIC, and CS
 
systems. The condensate water storage tanks and the demineralized water storage tank
 
provide high purity water for miscellaneous makeup uses throughout the plant, which includes
 
the reactor building.
The condensate and demineralized water system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the condensate
 
and demineralized water system could prevent the satisfactory accomplishment of an SR function. In addition, the condensate and demineralized water system performs functions that
 
support fire protection, and SBO.
The intended functions within the scope of license renewal include the following:
* provides a normally open water supply to the RHR system piping flow path, which continues to the HPCI system piping that is located up-stream of the HPCI system pump
* provides primary and secondary containment boundaries
* provides a water supply for both HPCI and RCIC systems during an SBO
* retains fission products by plateout on a surface
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.4.2, the applicant identified the following condensate and demineralized water system component types that are within the scope of license renewal and subject to an AMR:
bolting, condenser, expansion joint, fittings, piping, pumps, restricting orifice, tanks, tubing, and valves.2.3.4.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.2 and UFSAR Sections 10.13, 11.8, 11.9, F.6.10, and F.6.18 using the evaluation methodology described in SER Section 2.3. The staff conducted its
 
review in accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER Section 2.1 related to NSR piping segments that support secondary containment, the applicant
 
expanded the system boundaries for the condensate and demineralized water system. By letter 2-134 dated May 31, 2005, the applicant submitted the results of its review of piping, supports, and other components outside secondary containment required to maintain the structural integrity of
 
secondary containment that are within the scope of license renewal in accordance with the
 
requirements of 10 CFR 54.4(a)(2) for secondary containment qualification. In the enclosure to
 
the May 31, 2005 letter, the applicant stated that additional piping, fittings, valves, and the
 
demineralized water tank have been added to scope. However, the component types do not
 
differ from those listed in LRA Table 2.3.4.2; therefore, no changes to the condensate and
 
demineralized water system portion of the LRA are required. The staff reviewed applicant's
 
submittals and found the expanded scope of components to be acceptable, because the applicant had adequately included NSR components with the configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR piping or components.
2.3.4.2.3  Conclusion
 
The staff reviewed the LRA and RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff performed a review to determine whether any components that
 
should be subject to an AMR had not been identified by the applicant. No omissions were
 
identified. On the basis of its review, the staff concluded that there is reasonable assurance that
 
the applicant had adequately identified the condensate and demineralized water system
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the condensate and demineralized water system components that are subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3.4.3  Feedwater System 2.3.4.3.1  Summary of Technical Information in the Application In LRA Section 2.3.4.3, the applicant descr ibed the FW system. The FW system provides demineralized water at an elevated temperature to the reactor vessel during normal plant
 
operations. FW is fed to the reactor vessel through six feedwater inlet nozzles. Suction for the
 
system is drawn from the c ondensate system and FW is delivered to the reactor vessel at a controlled rate in order to maintain a stable reactor vessel water level. The system provides a
 
flow path to the reactor vessel for the HPCI, RCIC, and RWCU systems.
The FW system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the FW system could prevent the satisfactory
 
accomplishment of an SR function. In addition, the FW system performs functions that support
 
fire protection, EQ, ATWS, and SBO.
The intended functions within the scope of license renewal include the following:
* provides RCPB
* provides primary and secondary containment boundaries
* provides a path for HPCI system flow to the reactor pressure vessel through the feedwater spargers 2-135
* provides an injection path for the RCIC system
* provides a pressure boundary of the FW system components connected to the control air system that must maintain a pressure boundary in support of supplying containment
 
atmosphere dilution to the MSRVs
* restricts flow
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.4.3, the applicant identified the following FW component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings, piping, RCPB piping, RCPB restricting orifice, tubing, valves, and RCPB valves.
2.3.4.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.3 and UFSAR Sections 3.7, 4.2, 4.7.5, 4.9, 4.11, 5.2.3, 5.3, 6.4.1, 7.2, 7.3, 7.4, 7.8, 7.10, 10.17, and 11.8 using the evaluation methodology described
 
in SER Section 2.3. The staff conducted its review in accordance with the guidance described in
 
SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did
 
omit from the scope of license renewal any components with intended functions delineated
 
under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had
 
identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER Section 2.1 related to NSR piping segments that support secondary containment, the applicant expanded the system boundaries for the feedwater system. By letter dated May 31, 2005, the applicant submitted the results of its review of piping, supports, and other components outside secondary containment required to maintain the structural integrity of secondary containment that are within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2) for secondary containment qualification. In the enclosure to its letter dated May 31, 2005, the applicant stated that additional piping, valves, and heaters were added to scope. The component type, "heaters," was added to LRA Table 2.3.4.3.
The staff reviewed the NSR piping segments and found the expanded scope of components to be acceptable, because the applicant had adequately included NSR components with the configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR piping or components.
2-136 2.3.4.3.3  Conclusion The staff reviewed the LRA and RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff performed a review to determine whether any components that
 
should be subject to an AMR had not been identified by the applicant. No omissions were
 
identified. On the basis of its review, the staff concluded that there is reasonable assurance that
 
the applicant had adequately identified the FW system components that are within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and the FW system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.4.4  Heater Drains and Vents System 2.3.4.4.1  Summary of Technical Information in the Application In LRA Section 2.3.4.4, the applicant described the heater drains and vents system. The heater drains and vents system controls and contains the drains and vent paths from the various heaters associated with the main turbine cycle.
The heater drains and vents system contains SR components that are relied upon to remain functional during, and following, DBEs.
The intended functions within the scope of license renewal include the following:
* establishes an MSIV leakage pathway to the condenser
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.4.4, the applicant identified the following heater drains and vents system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, piping, traps, valves.
2.3.4.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.4 and UFSAR Section 11.8 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.4.4, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
2-137 Therefore, by letter to the applicant dated August 31, 2004, the staff issued RAIs concerning the specific issues to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAIs and the applicant's related responses.
In RAI 2.3.4.4-1, the staff stated that pressure reducing valves PCV-1-151, -153, -166, and -167 are highlighted on license renewal drawing 2-47E801-2-LR as being within the scope of license
 
renewal and subject to an AMR. However, the piping downstream of these pressure reducing
 
valves is not within the scope of license renewal. Likewise, the similar arrangement for Unit 3 is
 
shown on license renewal drawing 3-47E801-2-LR.
Pressure reducing valves typically do not provide isolation capability if the downstream piping fails. Failure of the downsteam piping could
 
effect the intended function of the heater drains and vents system that is required to establish
 
MSIV leakage pathway to the condenser per LRA Section 2.3.4.4. Therefore, the staff
 
requested that the applicant provide a basis for excluding the piping downstream of valves
 
PCV-1-151, -153, -166, and -167 from the scope of license renewal and from being subject to
 
an AMR.In its response, by letter dated October 19, 2004, the applicant stated that a calculation issued in support of the MSIV leakage path listed these valves as a boundary. These pressure
 
reducing valves close on loss of power, loss of air, and low steam line pressure. The applicant
 
stated that TVA will review the qualification of the MSIV leakage path to identify the piping, supports and other components past the isolation valve required to maintain the structural
 
integrity of the MSIV leakage pathway.
In a supplemental response dated May 31, 2005, the applicant provided the results of its review of the seismic qualification of the MSIV leakage path. As a result of the review, the following mechanical systems had systems boundary changes:
* main steam system
* auxiliary boiler system However, the component types do not differ from those listed in the corresponding LRA tables; therefore, no changes to these systems' portion of the LRA are required.
The following mechanical systems had syst ems boundary changes; however, new component types were added that affected the scoping/screening results in the LRA.
* heaters drains and vents system
* off-gas system The effect of these changes is evaluated and discussed in the corresponding sections of the SER. The remainder of the mechanical systems were not affected by this review.
Based on its review, the staff found the expanded scope of components to be acceptable, because the applicant had adequately included NSR components with the configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR piping or components. Therefore, the staff's concern described in RAI 2.3.4.4-1 is resolved.
2-138 In RAI 2.3.4.4-2, the staff stated that check valves 742 and 744 are highlighted on license renewal drawing 2-47E801-2-LR as being within the scope of license renewal and subject to an
 
AMR. However, the piping downstream of these check valves is not within the scope of license
 
renewal. Likewise, the similar arrangement for Unit 3 is shown on license renewal drawing
 
3-47E801-2-R. Failure of the downstream piping would affect the intended function of the heater
 
drains and vent system that is required to establish an MSIV leakage pathway to the condenser per LRA Section 2.3.4.4 and, therefore, should be within scope of license renewal as per
 
10 CFR 54.4(a)(2). Furthermore, the check valve orientation as shown on these drawings will
 
not prevent flow to the downstream piping in the event of a failure. Therefore, the staff
 
requested that the applicant provide a basis for excluding the piping downstream of check
 
valves 742 and 744 from being subject to an AMR.
In its response, by letter dated October 19, 2004, the applicant stated that a calculation issued in support of the MSIV leakage path has these valves listed as a boundary. The applicant
 
committed to review the qualification of the MSIV leakage path and identify the piping, supports
 
and other components past the isolation valve required to maintain the structural integrity of the
 
MSIV leakage pathway.
In a supplemental response dated May 31, 2005, the applicant stated that check valves 742 and 744 on boundary drawings 2-47E801-2-LR and 3-47E801-2-LR are spring-loaded and close on
 
low pressure upon MSIV closure to prevent backflow through these valves.
Based on its review, the staff found the applicant's response to RAI 2.3.4.4-2 acceptable, because it adequately addressed the intended function of check valves 742 and 744. Failure of
 
the downstream piping during low-pressure events will not impede the intended function of
 
these check valves. Therefore, the staff's concern described in RAI 2.3.4.4-2 is resolved.
In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER Section 2.1 related to NSR piping segments that support the MSIV leakage path, the applicant
 
expanded the system boundaries for the heaters dr ains and vents system. By letter dated May 31, 2005, the applicant submitted the results of its review of piping, supports, and other
 
components required to maintain the structural integrity of the MSIV leakage path that are within
 
the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2). In the
 
enclosure to the May 31, 2005 letter, the applicant stated that additional piping had been added
 
to scope. However, the component type does not differ from those listed in LRA Table 2.3.4.4;
 
therefore, no changes to the heater drains and vents system portion of the LRA are required.
 
The staff reviewed the NSR piping segments and found the expanded scope of components to
 
be acceptable because the applicant had adequately included NSR components with the
 
configuration that meets the scoping criterion of 10 CFR 54.4(a)(2) for the case where NSR
 
piping or components are directly connected to SR piping segments.
2.3.4.4.3  Conclusion
 
During its review of the information provided in the LRA, license renewal drawings, RAI responses, and licensing-basis information, the staff did not identify any omissions or
 
discrepancies in the applicant's scoping and screening results for the components of the heater
 
drains and vents system. Therefore, the staff concludes the heater drains and vent system components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and 2-139 that the applicant had adequately identified the heater drains and vents system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4.5  Turbine Drains and Miscellaneous Piping System 2.3.4.5.1  Summary of Technical Information in the Application In LRA Section 2.3.4.5, the applicant described the turbine drains and miscellaneous piping system. The turbine drains and miscellaneous piping system directs controlled leakage from
 
various MS system components into the condenser.
The turbine drains and miscellaneous piping system contains SR components that are relied upon to remain functional during, and following, DBEs.
The intended functions within the scope of license renewal include the following:
* establishes an MSIV leakage pathway to the condenser
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.4.5, the applicant identified the following turbine drains and miscellaneous piping system component types that are within the scope of license renewal and subject to an
 
AMR: bolting and valves.
2.3.4.5.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.5 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in accordance with the guidance described in
 
SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.4.5, the staff identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated October 8, 2004, the staff issued an RAI concerning
 
the specific issues to determine whether the applicant had properly applied the scoping criteria
 
of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAI and the applicant's response.
In RAI F 2.3.4.5-1, the staff stated that LRA Section 2.3.4.5 states that the intended function of the turbine drains and miscellaneous piping system is to establish MSIV leakage pathway to the
 
condenser. The entire LRA section is enclosed in a bold text box. LRA Appendix F, Section F.1, 2-140"Main Steam Isolation Valve Alternate Leakage Treatment," states that the Unit 1 main steam piping from the outermost isolation valve up to the turbine stop valve, the bypass/drain piping to
 
the main condenser, and the main condenser is being evaluated and modified as required to
 
ensure that the structural integrity is retained during, and following, an SSE. However, it is not
 
clear where the alternate leakage treatment flow path to the condenser exists on license
 
renewal drawings 2-47E807-2-LR and 3-47E807-2-LR. Therefore, the staff requested that the
 
applicant identify which portions of these drawings show components that are part of the
 
leakage pathway to the condenser.
In its response, by letter dated October 25, 2004, the applicant stated that the alternate leakage path ensures that process lines containing steam have a boundary that contains an isolation
 
point to form a preferred leakage path to the condenser. The boundary was established at the
 
first closed valve or fails-closed valve on the red lines continuing from LR drawings
 
2-47E801-2-LR, 2-47E807-1-LR, 3-47E801-2-LR, and 3-47E807-1-LR.
Based on its review, the staff found the applicant's response to RAI F 2.3.4.5-1 acceptable. It adequately identifies the portions of the license renewal drawings showing components that are
 
part of the leakage pathway to the condenser. Therefore, the staff's concern described in RAI F
 
2.3.4.5-1 is resolved.
2.3.4.5.3  Conclusion
 
The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI response described above to determine whether any SSCs that should be within the scope of license
 
renewal had not been identified by the applicant. No omissions were identified. In addition, the
 
staff performed a review to determine whether any components that should be subject to an
 
AMR had not been identified by the applicant. No omissions were identified. On the basis of its
 
review, the staff concluded that there is reasonable assurance that the applicant had adequately
 
identified the turbine drains and miscellaneous piping system components that are within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and the turbine drains and
 
miscellaneous piping system components that are subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3.4.6  Condenser Circulating Water System 2.3.4.6.1  Summary of Technical Information in the Application In LRA Section 2.3.4.6, the applicant described the condenser circulating water system. Each unit contains a condenser circulating water system that does not share any components with
 
the other units' systems. Each unit has three circulation water pumps that take water from a
 
common intake channel in Wheeler Reservoir. After passing through the condensers, the
 
heated water is cooled by the cooling towers or discharged directly back to Wheeler Reservoir.
 
Provisions, including a loop in the discharge conduit with a vacuum breaker, are made for the
 
prevention of the backflow of heated water into the intake channel, which serves as the ultimate
 
heat sink, if normal offsite power is lost. One condenser circulating water pump has more than
 
enough capacity to dissipate the shutdown heat for all three of the units.
2-141 The condenser circulating water system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the condenser circulating
 
water system could prevent the satisfac tory accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides a manual vacuum breaking capability to prevent backflow from cooling tower warm channel into the forebay upon trip of the condenser circulating water pumps
* provides mechanical closure
* provides structural support In LRA Table 2.3.4.6, the applicant identified the following condenser circulating water system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, piping, strainers, tubing, and valves.
2.3.4.6.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.6 and UFSAR Sections 2.4.2.2.2, 11.6, 12.2.7, and F.6.4 using the evaluation methodology described in SER Section 2.3. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed the components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.4.6, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, by letter to the applicant dated August 31, 2004, the staff issued RAIs concerning the
 
specific issues to determine whether the applicant had properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs
 
describe the staff's RAIs and the applicant's related responses.
In RAI 2.3.4.6-1, the staff stated that LRA Section 2.3.4.6 indicates that a vacuum-breaker valve, located in a piping loop in the discharge conduit of the condenser circulating water (CCW) system, is provided to prevent the backflow of heated cooling tower effluent from the
 
warm water channel into the intake channel which serves as an ultimate heat sink. Backflow
 
can occur upon loss of offsite power with attendant trip of the CCW pumps if the level in the
 
warm water channel exceeds that in the intake channel. As indicated in the LRA, the
 
components comprising this vacuum breaking subsystem require an AMR.
On the license renewal boundary drawings for Unit 1, all components comprising this subsystem are shown within the scope of license renewal in accordance with 10 CFR 54.4(a)(1). However, the drawings for Units 2 and 3 show only the vacuum-breaker valves themselves in scope under
 
10 CFR 54.4(a)(1), while the associated loop piping and fittings are shown either within scope 2-142 under 10 CFR 54.4(a)(2) or else outside of scope. Therefore, the staff requested that the applicant justify why the components comprising this subsystem had been classified differently
 
for Units 2 and 3 than for Unit 1.
In its response, by letter dated October 19, 2004, the applicant stated that DCN 51360A was issued to reclassify the loop piping and fittings of the above-mentioned subsystem from SR to
 
NSR, for all three units. However, at the time of the LRA submittal, implementation of this DCN
 
had been completed for Units 2 and 3 but not for Unit 1. This resulted in the differences in
 
classification noted above. Additionally, the applicant stated that the above referenced loop
 
components for Units 2 and 3, which are classified as outside the scope of license renewal, should have been classified as within scope under 10 CFR 54.4(a)(2). This error will be
 
corrected on the drawings for Units 2 and 3. It was further noted that, since DCN 51360A has
 
now been completed for Unit 1, the drawings for this unit have been revised to be consistent
 
with those for Units 2 and 3 and will be resubmitted as part of the annual update.
Based on its review, the staff found the applicant's response to RAI 2.3.4.6-1 acceptable. The differences in component classification noted above have been satisfactorily explained and the corresponding drawings have been appropriately corrected. Therefore, the staff's concern
 
described in RAI 2.3.4.6-1 is resolved.
In RAI 2.3.4.6-2, the staff stated that components of the CCW system that are subject to an AMR are shown in LRA Table 2.3.4.6. These components described in RAI 2.3.4.6-1 comprise
 
the vacuum breaking subsystem. For the components listed, the table shows that structural
 
support is the sole intended function for each (except bolting which has the additional intended
 
function of mechanical closure). However, it would appear that the pressure boundary of the
 
components comprising this subsystem must remain intact to effect a break in vacuum.
 
Accordingly, each of these components should have the additional intended function of
 
pressure boundary. Therefore, the staff requested that the applicant justify why the intended
 
function pressure boundary is not included in LRA Table 2.3.4.6 for each of the components
 
listed.In its response, by letter dated October 19, 2004, the applicant stated that maintaining an intact pressure boundary for the components listed in LRA Table 2.3.4.6 is not required, because the
 
vacuum-breaking valve in this subsystem coul d perform its intended function, even if leakage were to occur in the associated piping or fittings.
Based on its review, the staff found the applicant's response to RAI 2.3.4.6-2 acceptable. It adequately explains why the intended function of pressure boundary is not required for the
 
components in question. Therefore, the staff's concern described in RAI 2.3.4.6-2 is resolved.
2.3.4.6.3  Conclusion
 
The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI responses described above to determine whether any SSCs that should be within the scope of license
 
renewal had not been identified by the applicant. No omissions were identified. In addition, the
 
staff performed a review to determine whether any components that should be subject to an
 
AMR had not been identified by the applicant. No omissions were identified. On the basis of its
 
review, the staff concluded that there is reasonable assurance that the applicant had adequately
 
identified the condenser circulating water system components that are within the scope of 2-143 license renewal, as required by 10 CFR 54.4(a), and the condenser circulating water system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.4.7  Gland Seal Water System 2.3.4.7.1  Summary of Technical Information in the Application In LRA Section 2.3.4.7, the applicant described the gland seal water system. The gland seal water system provides pressurized sealing water to the condenser and condensate system
 
components that are under a vacuum in order to prevent air leakage into the condenser. Each
 
individual system has an elevated gland seal tank that is located in the reactor building and also
 
contains the associated piping that maintains a static pressure on seals (e.g., packing) of
 
components of the main condenser and condensate systems that are under a vacuum during
 
normal plant operations.
The gland seal water system contains SR components that are relied upon to remain functional during, and following, DBEs. The failure of NSR SSCs in the gland seal water system could
 
prevent the satisfactory accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides a secondary containment boundary
* provides mechanical closure
* provides pressure boundary
* provides structural support In LRA Table 2.3.4.7, the applicant identified the following gland seal water system component types that are within the scope of license renewal and subject to an AMR: bolting, fittings, piping, tanks, tubing, and valves.
2.3.4.7.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.7 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in accordance with the guidance described in
 
SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
 
had identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.4.7.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In
 
addition, the staff performed a review to determine whether any components that should be 2-144 subject to an AMR had not been identified by the applicant. No omissions were identified. On the basis of its review, the staff concluded that there is reasonable assurance that the applicant
 
had adequately identified the gland seal water system components that are within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and the gland seal water system components
 
that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-145 2.4  Scoping and Screening Results: Structures This section documents the staff's review of the applicant's scoping and screening results for structures. Specifically, this section discusses the following structures:
* boiling water reactor containment structures
* Class I Group 2 structures
* Class I Group 3 structures
* Class I Group 6 structures
* Class I Group 8 structures
* Class I Group 9 structures
* non-Class I structures
* structures and component supports commodities In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and list passive, long-lived structural SSCs that are within the scope of license renewal and subject to
 
an AMR. To verify that the applicant properly im plemented its methodology, the staff focused its review on the implementation results. This approach allowed the staff to confirm that there were
 
no omissions of structures and components that meet the scoping criteria and are subject to an
 
AMR.Staff Evaluation Methodology. The staff's evaluation of the information provided in the LRA was performed in the same manner for all structures. The objective of the review was to determine if
 
the components and supporting structures for a specific structure that appeared to meet the
 
scoping criteria specified in the Rule had been identified by the applicant as within the scope of
 
license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's
 
screening results to verify that all long-lived, passive components were subject to an AMR in
 
accordance with 10 CFR 54.21(a)(1).
Scoping. To perform its evaluation, the staff reviewed the applicable LRA section and associated component drawings, focusing its review on components that had not been identified
 
as within the scope of license renewal. The staff reviewed relevant licensing basis documents, including the UFSAR, for each structure and component to determine if the applicant had
 
omitted components with intended functions delineated under 10 CFR 54.4(a) from the scope of
 
license renewal. The staff also reviewed the licensing basis documents to determine if all
 
intended functions delineated under 10 CFR 54.4(a) were specified in the LRA. If omissions
 
were identified, the staff requested additional information to resolve the discrepancies.
Screening. Once the staff completed its review of the scoping results, the staff evaluated the applicant's screening results. For those structures and components with intended functions, the
 
staff sought to determine if the functions are performed with moving parts or a change in
 
configuration or properties, or if they are subject to replacement based on a qualified life or
 
specified time period, as described in 10 CFR 54.21(a)(1). For those that did not meet either of
 
these criteria, the staff sought to confirm that these structures and components were subject to
 
an AMR as required by 10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested
 
additional information to resolve them.
2-146 2.4.1  Boiling Water Reactor Containment Structures 2.4.1.1  Primary Containment Structure 2.4.1.1.1  Summary of Technical Information in the Application In LRA Section 2.4.1.1, the applicant described the primary containment structure. The primary containment structure is a General Electric Mark I containment design. Each unit has a primary
 
containment structure that is completely enclosed within the unit's reactor building. The main
 
function of the primary containment structure is to limit the release of fission products to the
 
environment in the event of a design-basis LOCA.The primary containment consists of a drywell, pressure suppression chamber, and a connecting vent system. The drywell is a steel pressure vessel enclosed in reinforced concrete.
 
The drywell contains the reactor vessel, reactor recirculation system, and portions of other
 
systems that form the reactor coolant pressure boundary. Also included within the drywell are
 
structural steel framing, electrical and me chanical equipment and system supports, a concrete shield wall around the reactor vessel, a removable steel head, a personnel airlock with two
 
mechanically interlocked doors, two equipment hatches, and miscellaneous electrical and
 
mechanical penetrations. The pressure suppression chamber is a steel, toroidal-shaped
 
pressure vessel. The pressure suppression chamber is commonly referred to as the "torus." The
 
torus includes internal steel framing, vent header, supports, access hatches, and penetrations.
 
The torus is mounted on support structures that transmit loads to the concrete foundation of the
 
reactor building. The drywell is connected to the pressure suppression chamber with eight
 
equally spaced vent lines. These vent lines are connected to a header, which is contained
 
within the air space of the pressure suppression chamber. The pressure suppression chamber
 
contains a large pool of water that condenses the steam from a failure of the reactor coolant
 
pressure boundary piping in the drywell. The pool also condenses steam from the main steam
 
relief valve discharge, high pressure coolant injection, and reactor core isolation cooling turbine
 
discharge.
The primary containment structure contains SR SSCs that are relied upon to remain functional during, and following, DBEs to ensure the integrity of the reactor coolant pressure boundary, shut down the reactor and maintain it in a safe shutdown condition, and prevent or mitigate the
 
consequences of accidents that could result in potential offsite exposure. The failure of NSR
 
SSCs in the primary containment structure could prevent the satisfactory accomplishment of an SR function. In addition, the primary containment structure performs functions that support fire
 
protection, EQ, ATWS, and SBO.
The intended functions within the scope of license renewal include the following:
* provides structural support and shelter/protection for components relied upon to demonstrate compliance with fire protection, EQ, and ATWS regulated events
* provides structural support and shelter/protection for SR components, NSR components, and components relied upon to demonstrate compliance with the SBO regulated event
* limits and controls the release of fission products to the secondary containment during DBAs 2-147
* provides sufficient air and water volumes to absorb the energy released to the containment during DBAs
* provides a source of water to the emergency core cooling systems
* provides protection to personnel and components from radiation
* provides a pressure boundary
* shelters and protects a component from the effects of weather or localized environmental conditions
* reduces a radiation dose
* provides structural and functional support for structures and components that are within the scope of license renewal In LRA Table 2.4.1.1, the applicant identified the following primary containment structure component types that are within the scope of license renewal and subject to an AMR:
* caulking and sealants
* compressible joints and seals
* controlled leakage doors
* hatches/plugs
* high density shielding concrete
* electrical and I&C penetrations
* mechanical penetrations
* reinforced concrete beams, columns, walls, and slabs
* steel containment elements
* structural bellows
* structural steel beams, columns, plates, and trusses 2.4.1.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.1.1 and UFSAR Sections 5.2, 12.2.2 and C.5 using the evaluation methodology described in SER Section 2.4. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.1.1 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
In RAI 2.4-2, dated December 20, 2004, the staff stated that in reviewing LRA Section 2.4.1.1, it noted that this section of the LRA should address not only the primary containment (drywell, 2-148 pressure suppression chamber, and the vent system connecting the two structures), but also all the structures inside the primary containment, all attachments to the containment, and the
 
containment supports. The staff also noted that LRA Table 2.4.1.1 identified the primary
 
containment component types requiring AMR and the associated component intended
 
function(s). Since LRA Table 2.4.1.1 combined many components under a single component
 
type, the staff requested that the applicant identify which component type had been intended to
 
cover the specific components listed in (a) through (k) below, or to identify the location in the
 
LRA where these specific components had been addressed. If these specific components had
 
not been considered to be within the scope of license renewal, the applicant was requested to
 
provide the technical bases for their exclusion. a.reactor vessel to biological shield stabilizers  b.biological shield to containment stabilizer c.reactor pressure vessel (RPV) male stabilizer attached to outside of drywell shell d.RPV female stabilizer and anchor rods (also referred to as gib) embedded in reactor building concrete wall    e.biological shield wall and anchor bolts f.reactor vessel support skirt and anchor bolts g.reactor vessel support ring girder and anchor bolts h.reactor vessel support pedestal i.drywell internal steel shear ring j.drywell steel support skirt and anchor bolts k.drywell head closure bolts and double gasket, tongue-and-groove seal arrangement By letter dated January 24, 2005, the applicant provided the following response:
The Primary Containment Structure scoping and screening results are presented in LRA Section 2.4.1.1, the Reactor Vessel scoping and screening results are presented in LRA
 
Section 2.3.1.1, and the Structures and Component Supports Commodity Group scoping
 
and screening results are presented in LRA Section 2.4.8.1. The following list of
 
components roll-up to the listed component groups:(a) Reactor Vessel to Biological Shield Stabilizers:
* Table 2.4.8.1, ASME Equivalent Supports and Components;
* Table 3.5.2.26, ASME Equivalent Supports and Components;
* Table 2.3.1.1, Stabilizer Bracket;
* Table 3.1.2.1, Stabilizer Bracket; and
* LRA Section 3.1.2.2.16.1 BWRVIP-74-A Table 4-1 Items.
* NOTE: This biological shield wall is internal to the drywell.
2-149(b) Biological Shield to Containment Stabilizer:
* Table 2.4.1.1, Steel Containment Elements; and
* Table 3.5.2.1, Steel Containment Element.
* NOTE: This biological shield wall is internal to the drywell.(c)  RPV Male Stabilizer Bracket Attached to Outside of Drywell Shell:
* There is no RPV male stabilizer bracket attached to the outside of the Drywell shell at BFN. There is a stabilizer from the internal biological
 
shield wall to the inside containment shell that is a subset of biological
 
shield to containment stabilizer noted in (b) above.(d) RPV Female Stabilizer and Anchor Rods (also referred to as Gib) embedded in Reactor Building concrete wall:
* There is no RPV female stabilizer and anchor rods (also referred to as Gib) embedded in Reactor Building concrete wall at BFN. There is a
 
female stabilizer and anchor rods assembly embedded in Reactor
 
Building concrete wall (also a biological shield wall external to Drywell)
 
and is a subset of biological shield to containment stabilizer noted in (b)
 
above.(e) Biological Shield Wall and Anchor Bolts:
* Table 2.4.1.1, High Density Shielding Concrete;
* Table 3.5.2.1, High Density Shielding Concrete (Un-reinforced shielding concrete is encased between steel plates and is inaccessible. The steel
 
plates are included with structural steel internal to drywell);
* Table 2.4.1.1, Structural Steel Beams, Columns, Plates, Trusses; and
* Table 3.5.2.1, Structural Steel Beams, Columns, Plates, Trusses.
* NOTE: This biological shield wall is internal to the drywell.(f)Reactor Vessel Support Skirt and Anchor Bolts:
* Table 2.3.1.1, Support Skirt and Attachment Welds;
* Table 3.1.2.1, Reactor Vessel Support Skirt and Attachment Welds;
* LRA Section 3.1.2.2.16.1 BWRVIP-74-A Table 4-1 Items;
* Table 2.4.8.1, ASME Equivalent Supports and Components; and
* Table 3.5.2.26, ASME Equivalent Supports and Components (includes anchor bolts).
2-150(g)Reactor Vessel Support Ring Girder and Anchor Bolts:
* Table 2.4.8.1, ASME Equivalent Supports and Components; and
* Table 3.5.2.26, ASME Equivalent Supports and Components (includes anchor bolts).(h)Reactor Vessel Support Pedestal:
* Table 2.4.1.1, Reinforced Concrete Beams, Columns, Walls, and Slabs; and
* Table 3.5.2.1, Reinforced Concrete Beams, Columns, Walls, and Slabs.(i) Drywell Internal Steel Shear Ring:
* BFN does not have a "Drywell Internal Steel Shear Ring"(j)Drywell Steel Support Skirt and Anchor Bolts:
* Table 2.4.1.1, Steel Containment Elements; and
* Table 3.5.2.1, Steel Containment Elements (Drywell steel support skirt is part of the Class MC drywell support and the skirt and anchor bolts are
 
encased in concrete; therefore, they are inaccessible.)(k)The Drywell Head Closure Bolts and Double Gasket, Tongue and Groove Seal Arrangement:
* Table 2.4.1.1, Steel Containment Elements;
* Table 3.5.2.1, Steel Containment Elements (Includes drywell head closure bolts);
* Table 2.4.1.1, Compressible Joints & Seals; and
* Table 3.5.2.1, Compressible Joints & Seals.
Based on the response to RAI 2.4-2 by letter dated January 24, 2005, the staff found that the components identified in the RAI are covered under the scope of LRA Section 2.4.1, except item (f), which is covered under the scope of LRA Section 2.3. However, 10 CFR 54.4(a) and (b)
 
require identification of all in-scope structures and components and their intended functions.
 
The staff reviewer assumed that the drywell and suppression chamber supports (items (j) and (k)) are within the scope of license renewal; however, an absence of all structural components
 
internal to drywells and suppression chambers (Items (a) to (e), and items (g) and (h)) from LRA
 
Table 2.4.1.1 implies that they are not within the scope of license renewal. The applicant was
 
requested to explicitly incorporate the components internal to drywells and suppression
 
chambers within the scope of license renewal, through cross referencing, if necessary.
In a follow-up response to RAI 2.4-2, by letter dated May 24, 2005, the applicant stated that the methodology used to determine the components within the scope of license renewal is
 
described in LRA Section 2.1.4.3.3, "Structural Component Scoping," and reads as follows:
2-151 For structures determined to be within the scope of 10 CFR 54, detailed structural drawings were reviewed to identify structural components (such as structural steel, foundations, floors, walls, ceilings, penetrations or stairways). For in-scope structures, all
 
structural components that are required to support the intended functions of the structure
 
were identified as in-scope of 10 CFR 54. These structural components were generally
 
evaluated as generic structural commodities, not as individual components.
LRA Section 2.4.1.1 addresses the primary containment structure and includes all component types, as noted in LRA Table 2.4.1.1. The co mponent type "Reinforced Concrete Beams, Columns, Walls, and Slabs" includes the concrete of the reactor vessel support pedestal and
 
other structural concrete located within the primary containment structure. The component type
 
"High Density Shielding Concrete" includes the concrete of the biological shield wall. The
 
component type "Structural Steel Beams, Columns, Plates, Trusses" includes the plates that
 
form the cylindrical shell of the biological shield wall and other structural steel components such
 
as the steel platforms located within the pr imary containment structure. The component type "Steel Containment Elements" includes the stabilizers between the biological shield wall and
 
containment shell, RPV male stabilizer bracket and RPV female stabilizer and anchor bolts, drywell, drywell steel support skirt and anchor bolts, drywell head and closure bolts, torus and
 
torus ring girder, embedded steel, and other components that comprise the primary containment
 
boundary of the primary containment structure.
The component type "Compressible Joints and Seals" includes the gasket material used in the drywell head seal, drywell and torus access
 
hatch seals, and personnel access doors and penetration seals located in the primary
 
containment structure. Components identified as supports that are located within the primary
 
containment structure were addressed in Section 2.4.8.1, Structures and Component Supports
 
Commodity Group. The component type "ASM E Equivalent Supports and Components" includes the anchor bolts of the RPV support skirt, RPV ring girder and anchor bolts and other
 
supports for ASME Code Class 1 and Class 2 piping within the primary containment structure.
Based on this detailed description of the commodity groups that are included within the scope of license renewal, the staff found that all structural as well as non-structural (e.g., seals and
 
gaskets) components within the primary containment structures have been included within the
 
scope of license renewal. Therefore, the staff found the applicant's scoping of the components
 
within the primary containment acceptable, and the staff's concern described in RAI 2.4-2 is
 
resolved.In RAI 2.4-3, dated December 20, 2004, the staff explained its concern that leakage through the refueling seals located at the top of the drywell potentially exposes the carbon steel drywell shell
 
inner and outer surfaces to loss of material due to corrosion. This is a particular concern for the
 
embedded portion of the drywell shell. Corrosion detected on the outer shell surface in the sand
 
pocket region in a number of Mark I steel containments has been attributed to leakage past the
 
drywell-to-reactor building refueling seal, coupled with clogging of the sand pocket drains.
 
Leakage into the drywell past the reactor vessel-to-drywell refueling seal creates the potential
 
for corrosion of the inaccessible portion of the inner surface of the drywell shell embedded in the
 
concrete floor.
From the information contained in the LRA, the staff stated that it was not clear (1) whether the refueling seals had been included within the scope of license renewal, and (2) if included, how
 
aging management of the seals was addressed. Therefore, the staff requested the applicant to
 
verify that the BFN plants' refueling seals were included in a component type that required an 2-152 AMR, or a detailed explanation for their exclusion. The staff also requested the applicant to provide a detailed description of the plant-specific operating experience for the refueling seals in
 
all three 3 units, including incidences of degradation, method of detection, root cause, corrective
 
actions, and current inspection procedures.
In its response, by letter dated January 24, 2005, the applicant stated that BFN it had not included the refueling seals at the top of the drywell within the scope of license renewal, and
 
explained its logic as follows:
The performance of the drywell-to-reactor building refueling seal is not considered a safety-related function. The drywell to reactor building refueling seal and the reactor
 
pressure vessel (RPV)-to-drywell refueling seal, in conjunction with the refueling
 
bulkhead, provides a watertight barrier to permit flooding above the RPV flange while
 
preventing water from entering the drywell. Providing a watertight barrier to permit
 
flooding above the RPV flange in support of refueling operations is not a safety-related
 
function.Moreover, the applicant stated that the performance of the drywell-to-reactor building refueling seal is not considered a II over I issue by quoting 10 CFR 54.4(a)(2): "All non safety-related
 
systems, structures, and components whose failure could prevent satisfactory accomplishment of any of the functions identified in paragraphs (a)(1)(i), (ii), or (iii) of this section," and provided
 
the following explanation:
A postulated failure of the drywell-to-reactor building refueling seal can result in water intrusion into the annulus space around the drywell. This leakage can occur only during
 
refueling outages when the reactor cavity is flooded to allow movement of fuel between
 
the reactor and the fuel pool. However, water intrusion does not cause failure of the
 
drywell's intended function. Any water leakage resulting from a postulated failure of the
 
drywell-to-reactor building refueling seal could not remain suspended in the annulus
 
region for an indefinite period of time and would eventually be routed to the sand-pocket
 
area drains or would evaporate due to the heat generated in the drywell during
 
operation.
The staff disagreed with the applicant's rationale for not including the reactor building-to-drywell refueling seals within the scope.
In OI 2.4-3, the staff explained that Supplement 1 of IE IN 86-99 indicates that if leakage from the flooded reactor cavity is not monitored and managed, there is a potential for corrosion of the
 
cylindrical portion of the drywell shell. As this corrosion would initiate in the non-inspectible
 
areas of the drywell, it cannot be monitored by IWE inspections. Moreover, this degradation of
 
the drywell shell can occur even if there is very little water found in the sand pocket area of the
 
drywell. Thus, the reactor building-to-drywell refueling seal becomes a nonsafety item, that can
 
affect the integrity of the drywell shell (which is a pressure boundary component) during the
 
period of extended operation, and falls under the requirement of 10 CFR 54.4(a)(2).
 
Furthermore, the staff offered an alternative by citing two BWR plants where the staff had
 
accepted in the past an alternative to managing the aging of the seal. The alternative is to
 
periodically perform ultrasonic testing (UT) of t he cylindrical portion of the drywell shell with an acceptable sampling program, as part of the containment ISI program. After reviewing the
 
response to RAI 3.5-4 (in the applicant's letter dated January 31, 2005) related to the operating 2-153 experience of drywell shell corrosion at all three units of BFN, the staff came to the conclusion that the applicant should manage the aging (leakage) of refueling seals. The applicant was
 
requested to include the refueling seals within the scope of license renewal.
In its response, by letter dated May 31, 2005, the applicant emphasized that BFN does not include the refueling seals at the top of the drywell in the scope of license renewal and provided
 
the following technical basis for that conclusion:
The drywell-to-reactor building refueling seal and the reactor pressure vessel (RPV)-to-drywell refueling seal, in conjunction with the refueling bulkhead, provide a
 
watertight barrier to permit flooding above the RPV flange while preventing water from
 
entering the drywell. Providing a watertight barrier to permit flooding above the RPV
 
flange in support of refueling operations is not a safety-related function. 10 CFR 54.4(a)
 
sets forth the criteria that determine whether plant systems, structures, and components
 
are within the scope of license renewal. The refueling seals do not satisfy any of the
 
requirements set forth in 10 CFR 54.4(a)(1). The refueling seals are not safety related
 
and they are not relied upon to remain functional during design basis events to ensure
 
10 CFR 54.4(a)(1)(i) the integrity of the reactor coolant pressure boundary, 10 CFR 54.4(a)(1)(ii) the capability to shut down the reactor and maintain it in a safe
 
shutdown condition, or 10 CFR 54.4(a)(1)(iii) the capability to prevent or mitigate
 
potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1),
50.67(b)(2), or 100.11. Thus, the refueling seals are not brought into scope of license
 
renewal by 10 CFR 54.4(a)(1).
Additionally, the applicant stated that the performance of the drywell-to-reactor building refueling seal and the RPV-to-drywell refueling seal, in conjunction with the refueling bulkhead is not
 
considered a II over I issue. 10 CFR 54.4(a)(2) states, "All non-safety-related systems, structures, and components whose failure could pr event satisfactory accomplishment of any of the functions identified in paragraphs (a)(1)(i), (ii), or (iii) of this section." A postulated failure of
 
the drywell-to-reactor building refueling seal can result in water intrusion into the annulus space
 
around the drywell. This leakage can occur only during refueling outages when the reactor
 
cavity is flooded to allow movement of fuel between the reactor and the fuel pool. However, water intrusion does not cause failure of the drywell's intended function. Any water leakage
 
resulting from a postulated failure of the drywell-to-reactor building refueling seal could not
 
remain suspended in the annulus region for an indefinite period of time and would eventually be
 
routed to the sand pocket area drains or would evaporate due to the heat generated in the
 
drywell during operation. The refueling seals are not relied upon in safety analyses or plant
 
evaluations to perform a function that demonstrates compliance with the NRC regulations for
 
fire protection, EQ, PRS (N/A for BWRs), ATWS, or SBO. The applicant discussed in detail the
 
differences between condition of the BFN units and that of Dresden 3, and emphasized that the
 
BFN refueling seals are not within the scope of license renewal and do not require aging
 
management review. The applicant also pointed out that Hatch Units 1 and 2 (NUREG-1803),
Peach Bottom Units 2 and 3 (NUREG-1769) and Dresden Units 2 and 3 and Quad Cities 1 and
 
2 (NUREG-1796) did not identify refueling seals to be within the scope of license renewal.
 
Thereafter, the applicant provided a detailed description of the BFN steel shell inspections in the
 
sand pocket areas (these are discussed in the staff's evaluation of RAI 3.5-4), and concluded:
 
"Based on Browns Ferry scoping results, Browns Ferry operating experience, and prior industry precedents, Browns Ferry refueling seals are not in the scope of license renewal, nor are
 
additional drywell inspections warranted at Browns Ferry."
2-154 Follow-up OI RAI 2.4 In a detailed response to the staff's follow-up item 3.5-4 related to the seal area near the drywell flange, by letter dated May 31, 2005, the applicant stated:
This area is exposed to standing water and repeated wetting and drying during refueling operations. The area is not accessible for detailed visual examination from the outside
 
surface. There are no documented UT thickness measurements of this area. No
 
previous problems have been documented relative to degradation of this area. Standing
 
water was observed in this area during the April, 1998 Unit 3 mid-cycle outage, during a
 
walkdown performed immediately following drywell head removal and prior to floodup.
 
Since the true surface condition can not be determined by visual examination or review
 
of existing data, this area appears to warrant additional investigation to determine
 
whether it should be included for augmented examination.
In its response, the applicant also provided a description of the limited number of UT measurements taken. The staff expressed its belief that 10 CFR 54.4(a)(2) applies to the
 
uninspectable side of the drywell shell, as significant corrosion of the drywell shell would
 
jeopardize capability of the primary containment to prevent or mitigate the consequences of
 
accidents as per 10 CFR 54.4(a)(1)(iii). Based on the applicant's responses to RAI 2.4-3, and
 
the follow-up RAI 3.5-4, the staff did not insist on having the drywell-to-reactor building seal
 
within the scope of license renewal. However, the staff indicated that it needed assurance that
 
the potential degradation of the uninspectable side of the drywell will be monitored and
 
managed during the period of extended operation. This remained as OI 2.4-3.
In its letter dated November 16, 2005, the applicant explained that to provide the staff with the necessary assurance that the potential degradation of the uninspectable side of the drywell is
 
being monitored and managed, the applicant will perform one-time confirmatory ultrasonic
 
thickness measurements on a portion of the cylindric al section of the drywell in a region where the liner plate is 0.75 inches thick. These ultrasonic thickness measurements will be obtained at
 
four locations, approximately 90° apart, in an area at least three feet by three feet with
 
measurements taken at intersection points of appr oximately one-foot grids. This will provide a bounding condition since the nominal thickness of the wall in this region has the least margin.
 
These ultrasonic thickness measurements will be obtained on Unit 2 and Unit 3 prior to the
 
period of extended operation to provide added assurance that the integrity of the drywell shell is
 
not being compromised by wastage before entering into the renewed licensing period.
For Unit 1, the applicant explained that it will perform one-time confirmatory ultrasonic thickness measurements on the vertical cylindrical area i mmediately below the drywell flange. This area is exposed to standing water and repeated wetting and drying during refueling operations. These
 
ultrasonic thickness measurements will be obtained on the entire vertical portion of the liner
 
accessible from inside drywell above elevation 637.0' (Az 0° - Az 360°) with measurements taken at intersection points of approximately one-foot grids. These ultrasonic thickness
 
measurements will be obtained prior to Unit 1 restart. Similar inspections have been performed on Units 2 and 3 in this area as documented in BFN plant procedure 0-TI-376, Appendix 9.7. A
 
discussion of the inspection for Units 2 and 3 is contained in the applicant's response to
 
follow-up RAI 3.5-4, page E-13 in the letter from TVA to the NRC dated May 31, 2005.
The applicant, further asserted that data from the ultrasonic thickness measurements described above will be reviewed by its engineering division. If any areas of concern or non-conforming
 
conditions are identified, a PER will be initiated in accordance with the site Corrective Action 2-155 Program, SPP-3.1. A corrective action plan will be developed in accordance with SPP-3.1 and an extent of condition and applicability to the other BFN units would be considered in the
 
disposition of the PER.
As part of its response, the applicant emphasized that the BFN configuration of the refueling cavity-to-drywell seal is different from that of a number of other Mark I containments. There is no
 
gasket at the drain, and the applicant claimed that it is able to monitor the leakage from the
 
refueling seal, if it occurs. However, the applicant could not satisfactorily explain the root cause
 
of water in the sand pocket areas. Therefore, the applicant chose to monitor the cylindrical
 
inaccessible areas of the three BFN units. For Units 1 and 2, the applicant will perform an
 
augmented inspection of these areas one time prior to the periods of extended operation; and, for Unit 1, it will perform the inspection of these areas prior to Unit 1 restart. As part of these
 
inspections, if the applicant discovers non-conforming conditions, it will take appropriate
 
corrective actions. After careful review of the applicant's commitments, the staff considered the
 
approach proposed by the applicant acceptable; therefore, OI 2.4-3 is closed.
2.4.1.1.3  Conclusion
 
The staff reviewed the LRA, related structural components, and RAI responses described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
primary containment structure components that are within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and the primary containment structure components that are subject
 
to an AMR, as required by 10 CFR 54.21(a)(1).
 
====2.4.2 Class====
1 Group 2 Structures In LRA Section 2.4.2, the applicant identified the structures and components of the Class 1 Group 2 structures that are subject to an AMR for license renewal.
The applicant described the supporting structures and components of the Class 1 Group 2 structures in the following sections of the LRA:
* 2.4.2.1reactor buildings
* 2.4.2.2equipment access lock The corresponding subsections of the SER, 2.4.2.1 - 2.4.2.2, present the staff's review findings with respect to the Class 1 Group 2 structures for BFN.
2.4.2.1  Reactor Buildings 2.4.2.1.1  Summary of Technical Information in the Application In LRA Section 2.4.2.1, the applicant described the reactor buildings. Each unit has its own reactor building that completely encloses the reactors, the primary containment structures, and
 
the auxiliary and emergency systems of the nuc lear steam supply system (NSSS). A major 2-156 substructure of the reactor building is the reinforced concrete biological shield that surrounds the drywell portion of the primary containment. The reactor buildings house features such as the
 
spent fuel pool, steam dryer/moisture separator storage pool, reactor cavity, reactor auxiliary
 
equipment, refueling equipment, reactor servicing equipment, and the control bay. The control
 
bay houses the main control room that is required for plant operation and the operation of other
 
important auxiliary systems. The reactor building consists of monolithic, reinforced concrete floors and walls from the foundation to the refueling floor. The refueling floor is common for all
 
three units and is enclosed by the steel superstructure with metal siding and a built-up roof.
 
Blowout or pressure relief panels are installed as part of the reactor building superstructure to
 
relieve pressure during a DBA or DBE.
The reactor buildings contain SR components that are relied upon to remain functional during and following DBEs. The failure of NSR SSCs in the reactor buildings could prevent the
 
satisfactory accomplishment of an SR function. In addition, the reactor buildings perform
 
functions that support fire protection, EQ, ATWS, and SBO.
The intended functions within the scope of license renewal include the following:
* provides controls for the potential release of fission products to the external environment
* provides a secondary containment function when the primary containment is required to be in service
* provides a primary containment function during reactor refueling and maintenance operations when the primary containment systems are open
* provides radiation shielding protection for personnel, equipment, and components
* provides structural support and shelter/protection for components relied upon to demonstrate compliance with the fire protection, EQ, and ATWS regulated events
* provides structural support and shelter/protection for SR components, NSR components, and components relied upon to demonstrate compliance with the SBO regulated event
* provides protection for the safe storage of new and spent fuel
* prevents criticality of new and spent fuel
* allows for expansion of a component
* provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of the plant
* provides flood protection barrier for internal and external flooding events
* provides protection against the effects of a high-energy or low-energy (moderate) line break
* provides a barrier for protection against internally or externally generated missiles
* provides a pressure boundary
* shelters and protects a component from the effects of weather or localized environmental conditions
* reduces a radiation dose 2-157
* provides structural and functional support for structures and components within the scope of license renewal
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.2.1, the applicant identified the following reactor buildings component types that are within the scope of license renewal and subject to an AMR:
* bolting and fasteners
* caulking and sealants
* compressible joints and seals
* controlled leakage doors
* expansion joints
* fire barriers
* hatches and plugs
* masonry block
* metal roofing
* metal siding
* electrical and I&C penetrations
* mechanical penetrations
* reinforced concrete beams, columns, walls, and slabs
* roof membrane
* spent fuel pool liners
* spent fuel storage racks (includes new fuel storage racks)
* structural steel, beams, plates, and trusses 2.4.2.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.2.1 and UFSAR Sections 5.3 and 12.2.2 using the evaluation methodology described in SER Section 2.4. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.2.1 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
The staff noted that LRA drawing 0-10E201-01-LR, "License Renewal Screening for Information Only Location of Structures," identifies structures that are not within scope of license renewal.
 
These structures include east access facility, isolation valve pits, radwaste building, south
 
access retaining walls, water and oil storage building, part of gate structure No.2 adjacent to 2-158 diesel high-pressure fire pump house, raw water treatment facility, structural elements within the transformer yard, and other miscellaneous buildings. It was not clear to the staff that all of the
 
above listed structures serve no intended function as defined in 10 CFR 54.4(a)(1).
In RAI 2.4-1, dated December 20, 2004, the staff asked the applicant to provide additional descriptive information for the above-listed structures, define their function, and describe the
 
technical bases for exclusion from the license renewal scope. The applicant was also requested
 
to verify that none of these structures serve a seismic II/I intended function as defined in
 
10 CFR 54.4(a)(2).
In its response, by letter dated January 24, 2005, the applicant stated the following:
These five (5) structures; East Access Facility, Radwaste Building, Water and Oil Storage Building, part of Gate Structure No.2 adjacent to Diesel High Pressure Fire
 
Pump House, and Raw Water Treatment Facility are groups of Class II (NSR) structures
 
and major civil features that do not satisfy the requirements of 10 CFR 54.4(a). These
 
five structures provide structural support and anchorage for NSR equipment and
 
equipment that is not required to support regulated events (ATWS, fire protection, EQ, and SBO). None of the five structures and major components in these structural groups
 
serves a seismic II/I intended function. This was the technical basis for exclusion from
 
the license renewal scope. A more detailed description and functions is provided below
 
for each of the five structures. A more detailed description of the South Access Retaining
 
Walls, the Isolation Valve Pits, and the structural elements within the Transformer Yard
 
and other miscellaneous buildings is also provided below.
East Access Facility This facility is a set of two temporary Class II (non-safetyrelated) buildings built originally to support the recovery of BFN unit 3. One building provides office space and shop area
 
for site maintenance personnel. The other building provides access for site personnel, plant material and plant equipment into the powerhouse (through the unit 3 Turbine
 
Building) and a radiation control point for same entering or exiting the unit 3 Turbine
 
Building.
 
Isolation Valve Pits These Class II (non-safety-related) structures are manholes that provide structural support and shelter protection for the hardened wetwell vent piping and components.
 
Upon further review, it has been noted that the hardened wetwell vent is in scope for
 
license renewal per section 2.3.2.1, C ontainment System (064). The hardened wetwell vent was a commitment to GL 89-16. These isolation valve pits are Class II (NSR)
 
structures and since they provide an intended function for an in-scope mechanical
 
system (54.4(a)(2)), they should be included within the scope of the LRA. Refer to for the affected sections of the application with the required scoping, screening and aging management review results for these structures (manholes).
Radwaste Building The Radwaste Building is a Class II (non-safety-related) structure per UFSAR section 12.2.5. The Radwaste Building is a cellular box-type concrete structure extending 2-159 approximately 20 feet below grade and 30 feet above grade and is supported by steel H-piles driven to bedrock. This building houses common services to all three units. The
 
concrete structure provides shelter/protection and non-safety related structural support
 
for equipment and components that support the processing of radwaste generated as a
 
result of plant operation.
 
South Access Retaining Walls These retaining walls are safety-related structural features that maintain the stability of the safety-related Earth Berm. The retaining walls provide retention of the Earth Berm
 
and allows for removal of a portion of the earth berm to construct a temporary personnel
 
access building. This temporary personnel access building provides access for site
 
personnel into the unit 1 Reactor Building and a radiation control point for same entering
 
or exiting the unit 1 Reactor Building during unit 1 recovery. These retaining walls are
 
safety-related structural features and should be included in the LRA. Refer to for the affected sections of the application with the required scoping, screening and aging management review results for this structural feature.
Water and Oil Storage Building The Water and Oil Storage Building is a Class II (non-safety related) of light commercial construction, housing non-safety related electrical components and equipment for the
 
non-safety related water and oil storage tanks located east of this building.
 
Part of Gate Structure No. 2 adjacent to Diesel HPFP House Gate Structure No. 2 is part of the Auxilia ry Condenser Cooling Water System as shown on UFSAR Figure 12.2-72a (TVA drawing 0-31E400-1). The system consists of
 
waterways, control structures (i.e., Discharge Control Structure and Gate Structure No.
: 2) and cooling towers to permit helper system operation. They are seismically
 
unclassified and were designed for normal applicable dead, live, and surcharge loads
 
with appropriate load factors. The Diesel HPFP House is also a Class II structure and
 
was determined to be in-scope for LR because it houses mechanical and electrical
 
components that support the regulated event 50.48. Consequently seismic events do not have to be considered to occur with the regulated event 50.48.
 
Raw Water Treatment Facility The Raw Water Treatment Facility is a Class II (non-safetyrelated) prefabricated facility housing non-safety-related equipment and tanks for chemical injection into the raw
 
cooling and service water systems. The function of the facility is to provide
 
shelter/protection and non-safety-related structural support for the equipment and
 
components in this facility. A small office space for transit personnel is provided in one of
 
the buildings.
Structural Elements within the Transformer Yard and other miscellaneous buildings The Transformer Yard is in the scope of license renewal based on the criteria of 54.4(a)(3) for Station Blackout. See LRA section 2.4.7.4 for Transformer Yard scoping
 
and screening results. Note that the 161 kV Switchyard (LRA section 2.4.7.5) and the
 
500 kV Switchyard (LRA section 2.4.7.6) are also in the scope of license renewal based 2-160 on the criteria of 54.4(a)(3) for Station Blackout. There are no permanent buildings within the license renewal boundary diagram for Transformer Yard or 161 kV Switchyard or
 
500 kV Switchyard.
The staff reviewed the above response including the Attachments 1 and 2 of the applicant's letter dated January 24, 2005. The applicant committed to include the structural components
 
discussed in these attachments as part of the LRA update. The staff provided its evaluation of
 
the structures for isolation valve pits and south access retaining walls discussed in SER
 
Sections 2.4.7.7 and 2.4.3.9, respectively. The staff found that the response is adequate and
 
acceptable. Therefore, the staff's concern described in RAI 2.4-1 is resolved.
In RAI 2.4-4, dated December 20, 2004, the staff stated that LRA Table 2.4.2.1 presents a list of component types that are part of the reactor building, the auxiliary and emergency systems of the NSSS, the biological shield, the spent fuel pool, the steam dryer/moisture separator storage
 
pool, the reactor cavity reactor auxiliary equipment, the steel superstructure with metal siding
 
and the built-up roof. Therefore, the staff requested the applicant to provide a description of the "Neutron-Absorbing Sheets" used for the spent fuel storage racks and confirm that they are part
 
of the spent fuel storage racks listed in LRA Table 2.4.2.1.
In its response, by letter dated January 24, 2005, the applicant stated:
NUREG 1801, Section VII.A2.1-b, identifies "Spent Fuel Storage Racks - neutron
 
absorbing sheets" as a component type. In BFN LRA Section 2.3.3.27 "Fuel Handling
 
and Storage System (079)," it states that the spent fuel pool components are evaluated
 
as structural components in Section 2.4.2.1 "Reactor Building Structure". BFN LRA
 
Table 2.4.2.1 "Reactor Building Structure" identifies "Spent Fuel Storage Racks (includes
 
new fuel storage racks)" as a component requiring aging management. The "Neutron
 
Absorbing Sheet" is a component of the BFN spent fuel storage rack container tube wall
 
and is comprised of Boral sandwiched within the stainless steel wall of each container
 
tube.The staff found the above response acceptable. Therefore, the staff's concern described in RAI 2.4-4 is resolved.
In RAI 2.4-5, dated December 20, 2004, referring to LRA Section 2.4.2.1, the staff requested the applicant to clarify if the reactor buildings are designed to maintain an internal negative pressure
 
under neutral wind conditions in order to serve as the secondary containment whose primary
 
purpose is to minimize the ground level release of airborne radioactive materials and to provide
 
for a controlled, elevated release of the building atmosphere under accident conditions. If this
 
assumption was correct, the staff wanted to know if reactor building pipe penetrations were
 
provided with some type of silicone rubber seals that allow pipe movement and provide a seal
 
between the pipe and the reactor buildings and maintain the negative internal pressure. The
 
staff wanted the applicant to confirm that these penetration seals are included within the scope
 
of licence renewal and are included in LRA Table 2.4.2.1.
In its response, by letter dated January 24, 2005, the applicant stated:
With the exception of the Control Room, the Reactor Building is designed to maintain an internal negative pressure under neutral wind conditions in order to serve as the 2-161 secondary containment whose primary purpose is to minimize the ground level release of airborne radioactive materials and to provide for a controlled, elevated release of the
 
building atmosphere under accident conditions. The Control Room and portions of the
 
Control Bay that are contained within the Reactor Building are maintained at a positive
 
pressure to prevent the introduction of fission products during design basis events.
 
Piping that is not anchored within a reinforced concrete wall is sealed with caulking or
 
sealants. The reinforced concrete wall, and caulking and sealants are identified as
 
component type "Reinforced Concrete Beams, Columns, Walls, and Slabs" and
 
"Caulking & Sealants" respectively in Table 2.4.2.1 as requiring aging management
 
review with a pressure boundary (PB) intended function.
The staff found the above response adequate and acceptable. Therefore, the staff's concern described in RAI 2.4-5 is resolved.
In RAI 2.4-12, dated December 20, 2004, the staff stated that based on information provided in LRA Sections 2.4.2.1, 2.4.2.2, 2.4.3.1, 2.4.4.1, and 2.4.7.1, it was unclear which cranes and
 
hoists were determined to be within the scope of license renewal and which subset of the
 
in-scope items have been screened in as items requiring an AMR. Therefore, the staff
 
requested the applicant to clarify the treatment of cranes and hoists in the scoping and
 
screening, and in the AMR. The applicant was requested to submit the following information:
* A list of all cranes, hoists, rails, and associated components in the scope of license renewal.
* Additional information to identify the location within the LRA where cranes, hoists, rails, and associated components are addressed. If these specific components are not
 
considered to be within the scope of license renewal, provide the technical bases for
 
their exclusion.
* A list of all cranes, hoists, rails, and associated components requiring an AMR (i.e., passive, long-lived components).
* A list of all cranes, hoists, rails, and associated components requiring aging management and/or TLAA.
In its response, by letter dated January 24, 2005, the applicant stated that the cranes and hoists are addressed in LRA Section 2.3.3.34 and the AMR results are contained in Table 3.3.2.34.
 
This same question was asked in RAI 2.3.3.34-1, dated August 31, 2004. In its response to
 
RAI 2.3.3.34-1 dated October 19, 2004, the applicant stated:
The following buildings that contain NSR cranes and monorails which could potentially prevent safety related SSCs from performi ng their intended function(s) are: Reactor Building, Primary Containment, Diesel Generator Buildings, Intake Pumping Station, and
 
Reinforced Concrete Chimney. All cranes and monorails in these buildings are in scope.
 
The Mobile A-frames is a crane on wheels. The A-frame cranes are in scope since they
 
could be used in a safety related building. This crane is subject to an AMR.
The staff found that the applicant had adequately responded to RAI 2.4-12 related to scoping and screening of cranes, hoists, rails, and associated components. Therefore, the staff's
 
concern described in RAI 2.4-12 is resolved.
2-162 2.4.2.1.3  Conclusion The staff reviewed the LRA, related structural components, and RAI responses described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
reactor buildings components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the reactor buildings components that are subject to an AMR, as required
 
by 10 CFR 54.21(a)(1).
2.4.2.2  Equipment Access Lock 2.4.2.2.1  Summary of Technical Information in the Application In LRA Section 2.4.2.2, the applicant described the equipment access lock. The equipment access lock is a shared feature for all three reactor buildings. The equipment access lock is a
 
reinforced concrete structure, supported on piles, located on the south end of the Unit 1 reactor
 
building. The structure is sized to allow for the passage of a railcar or a tractor trailer within the
 
structure. This allows for the transit of large equipment into, or out of, the reactor buildings, while maintaining the secondary containment. The equipment access lock is an airlock with
 
large equipment doors that open to the outside environment on the south end, and allow access
 
to the Unit 1 reactor building on the north end.
The equipment access lock contains SR components that are relied upon to remain functional during and following DBEs. The failure of NSR SSCs in the equipment access lock could
 
prevent the satisfactory accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides controls for the potential release of fission products to the external environment
* provides a secondary containment envelope between the reactor building and the outside entrance
* provides structural support and shelter/protection for SR and NSR components
* provides flood protection barrier for internal and external flooding events
* provides a barrier for protection against internally or externally generated missiles
* provides a pressure boundary
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support for structures and components within the scope of license renewal
* provides structural and functional support, for in-scope structures and components, by an NSR component 2-163 In LRA Table 2.4.2.2, the applicant identified the following equipment access lock component types that are within the scope of license renewal and subject to an AMR:
* caulking and sealants
* compressible joints and seals
* controlled leakage doors
* electrical and I&C penetrations
* mechanical penetrations
* piles
* reinforced concrete beams, columns, walls, and slabs
* structural steel beams, columns, plates, and trusses 2.4.2.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.2.2 and UFSAR Sections 5.3.3.5 and 12.2.9 using the evaluation methodology described in SER Section 2.4. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.4.2.2.3  Conclusion
 
The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the equipment access lock
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the equipment access lock components that are subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
 
====2.4.3 Class====
1 Group 3 Structures In LRA Section 2.4.3, the applicant identified the structures and components of the Class 1 Group 3 structures that are subject to an AMR for license renewal.
The applicant described the supporting structures and components of the Class 1 Group 3 structures in the following sections of the LRA:
* 2.4.3.1Diesel Generator Buildings
* 2.4.3.2Standby Gas Treatment Building
* 2.4.3.3Off-gas Treatment Building 2-164
* 2.4.3.4Vacuum Pipe Building
* 2.4.3.5Residual Heat Removal Service Water Tunnels
* 2.4.3.6Electrical Cable Tunnel from the Intake Pumping Station to the Powerhouse
* 2.4.3.7Underground Concrete Encased Structures
* 2.4.3.8Earth Berm
* 2.4.3.9South Access Retaining Walls (added LRA Section)
The corresponding subsections of the SER (2.4.3.1 - 2.4.3.9) present the staff's review findings with respect to the Class 1 Group 3 structures for BFN.
2.4.3.1  Diesel Generator Buildings 2.4.3.1.1  Summary of Technical Information in the Application In LRA Section 2.4.3.1, the applicant described the diesel generator buildings. The diesel generator buildings provide structural support and shelter/protection for the diesel generators (DGs) and other components within the scope of license renewal that are essential for the safe
 
shutdown of the plant when there is a sustained loss of off-site power. The Unit 1 and 2 diesel
 
generator building houses four DGs that provide power to the four shared Unit 1 and 2
 
shutdown boards that are located in the reactor buildings. The Unit 3 DG building houses four
 
DGs that provide power to the four separate unit shutdown boards that are located in the Unit 3
 
DG building.
The diesel generator buildings contain SR components that are relied upon to remain functional during and following DBEs. The failure of NSR SSCs in the diesel generator buildings could
 
prevent the satisfactory accomplishment of an SR function. In addition, the DG buildings
 
perform functions that support fire protection and SBO.
The intended functions within the scope of license renewal include the following:
* provides structural support and shelter/protection for SR and NSR components, and components that are relied upon to demonstrate compliance with the fire protection and
 
SBO regulated events
* provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of the plant
* provides flood protection barrier for internal and external flooding events
* provides a barrier for protection against internally or externally generated missiles
* provides a pressure boundary
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support for structures and components within the scope of license renewal 2-165
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.3.1, the applicant identified the following diesel generator building component types that are within the scope of license renewal and subject to an AMR:
* caulking and sealants
* compressible joints and seals
* controlled leakage doors
* fire barriers
* hatches/plugs
* masonry block
* metal siding
* electrical and I&C penetrations
* mechanical penetrations
* reinforced concrete beams, columns, walls, and slabs
* structural steel beams, columns, plates, and trusses 2.4.3.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.3.1 and UFSAR Sections 8.5, 12.2.8 and 12.2.13 using the evaluation methodology described in SER Section 2.4. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.3.1 identified an area in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant
 
responded to the staff's RAI as discussed below.
In RAI 2.4-8, dated December 20, 2004, the staff stated that LRA Section 2.4.3.1 refers to Units 1 and 2 DG building and Unit 3 DG building. The license renewal drawing
 
0-10E201-01-LR shows a diesel generator building at the west side of the reactor building and
 
another DG building at the east side, without indicating which DG building is designated for
 
Units 1 and 2 shutdown function. The other building is intended for shutdown of the Unit 3
 
reactor. Therefore, the staff requested the applicant to clarify this ambiguity and explain why the
 
four separate Unit 3 shutdown boards are located in Unit 3 DG building, whereas the other four
 
shared Units 1 and 2 shutdown boards are located in the reactor buildings. Also regarding LRA
 
Table 2.4.3.1, the applicant was asked to identify other items such as structural steel
 
embedments, carbon steel boltings, reinforced concrete foundation footings, grouted concrete, and water proofing membrane materials that require an AMR.
In its response, by letter dated January 24, 2005, the applicant stated:
2-166 The original layout for Browns Ferry was a two unit site with a common Diesel Generator
 
Building (DGB). Unit 3 was added after the initial design and provided with its own Diesel
 
Generator Building and shutdown board rooms within the DGB. The following
 
components are also located in the Units 1 and 2 Diesel Generator Building and Unit 3
 
Diesel Generator Building and are evaluated as Structures and Component Supports
 
commodities in LRA Section 2.4.8:
* ASME Equivalent Supports and Components
* Cable Trays and Supports
* Conduit and Supports
* Electrical Panels, Racks, Cabinets, and Other Enclosures
* Equipment Supports and Foundations
* HVAC Duct Supports
* Instrument Line Supports
* Instrument Racks, Frames, Panels, & Enclosures
* Non-ASME Equivalent Supports and Components
* Stairs, Platforms, Grating Supports
* Tube Track The applicant noted that in-scope components evaluated in LRA Section 2.4.8 also include support structural members, welds, bolting, anchorage and building concrete at anchorage (including baseplate and grout) to the structure. Waterproofing membranes are not relied on to
 
support the intended functions of the structural components of the BFN structures.
The staff found the above response provided sufficient information to clarify the ambiguity noted in RAI 2.4-8. Therefore, the staff's concern described in RAI 2.4-8 is resolved.
2.4.3.1.3  Conclusion
 
The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
DG buildings components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the diesel generator buildings components that are subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.4.3.2  Standby Gas Treatment Building 2.4.3.2.1  Summary of Technical Information in the Application In LRA Section 2.4.3.2, the applicant described the SGT building. The SGT building houses shared components for all three units and prov ides a protected environment for the SGT system. The building consists of two double-barreled, reinforced concrete, box-frame structures
 
with closed ends. The two structures are located side-by-side and adjacent to the southwest 2-167 corner of the Unit 1 reactor building. The two structures also lie within the earth berm. One structure houses two SGT trains, and the other structure houses the remaining SGT train.
The SGT building contains SR components that are relied upon to remain functional during and following DBEs. The failure of NSR SSCs in the SGT building could prevent the satisfactory
 
accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides structural support and shelter/protection for SR and NSR components
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support for structures and components within the scope of license renewal
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.3.2, the applicant identified the following SGT building component types that are within the scope of license renewal and subject to an AMR:
* electrical and I&C penetrations
* mechanical penetrations
* reinforced concrete beams, columns, walls, and slabs 2.4.3.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.3.2 and UFSAR Sections 5.3 and 12.2.10 using the evaluation methodology described in SER Section 2.4. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.4.3.2.3 Conclusion
 
The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the SGT building 2-168 components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the SGT building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.3.3  Off-Gas Treatment Building 2.4.3.3.1  Summary of Technical Information in the Application In LRA Section 2.4.3.3, the applicant described the off-gas treatment building. The off-gas treatment building is an underground structure that houses the off-gas system charcoal
 
adsorbers and the supporting equipment for BFN. The exterior walls and bottom slab are
 
designed and constructed to maintain their structural integrity if a partial collapse of the
 
reinforced concrete chimney were to occur during an external event (i.e., seismic, tornadic, etc.). The maintained structural integrity would not permit water leakage into, or out of, the
 
building below an elevation of 566.25 feet.
The portions of the off-gas treatment building containing components subject to an AMR include the exterior walls and bottom slab.
The off-gas treatment building contains SR components that are relied upon to remain functional during and following DBEs.
The intended functions within the scope of license renewal include the following:
* prevents the release of radiation into the surrounding groundwater from the failure or collapse of the activated charcoal beds
* provides a pressure boundary In LRA Table 2.4.3.3, the applicant identified the following off-gas treatment building component types that are within the scope of license renewal and subject to an AMR:
* caulking and sealants
* mechanical penetrations
* reinforced concrete beams, columns, walls, and slabs 2.4.3.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.3.3 and UFSAR Section 12.2.14 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2-169 The staff's review of LRA Section 2.4.3.3 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4-9(a), dated December 20, 2004, the staff stated that LRA Section 2.4.3 lists several structures, that are not shown in drawing 0-10E201-01-LR. In LRA Section 2.4.3.3, the off-gas
 
treatment building is described to have only exterior walls and bottom slab, implying that there is
 
no top slab for the building. Therefore, the staff requested the applicant to confirm that the
 
building has no top slab and no component types (e.g., electrical and I&C penetrations, structural steel embedments, carbon steel boltings, reinforced concrete foundation footings, grouted concrete, and water proofing membrane materials, etc.), other than those listed in LRA
 
Table 2.4.3.3, that require an AMR.
In its response, by letter dated January 24, 2005, the applicant stated:
Section 2.4.3.3 of the LRA identifies the Off-Gas Treatment Building as an underground structure. The Off-Gas Treatment Building is an underground structure with exterior
 
walls, interior walls and slabs, bottom or foundation slab and a top slab. The exterior
 
walls and bottom slab are designed and constructed to maintain their structural integrity
 
during a partial collapse of the Reinforced Concrete Chimney during a design basis
 
event (tornado) so that they will not permit water leakage into or out of the building below
 
elevation 566.25 feet (Reference UFSAR 12.2.14). The top slab is not required for the
 
intended function of preventing release of radiation from the failure/collapse of the
 
activated charcoal beds into the surrounding groundwater. Other than the "Caulking and
 
Sealants," "Penetrations, Mechanical," and the "Reinforced Concrete Beams, Columns, Walls and Slabs" components noted on LRA Table 2.4.3.3, there are no other
 
components that require an aging management review.
The staff found that the applicant had adequately responded to the part of RAI 2.4-9(a) related to the off-gas treatment building structure. Therefore the staff's concern described in
 
RAI 2.4-9(a) is resolved.
2.4.3.3.3  Conclusion The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
off-gas treatment building components that are within the scope of license renewal, as required
 
by 10 CFR 54.4(a), and the off-gas treatment building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.3.4  Vacuum Pipe Building 2.4.3.4.1  Summary of Technical Information in the Application 2-170 In LRA Section 2.4.3.4, the applicant described the vacuum pipe building. The vacuum pipe building is a structure shared by all of the units. It is located underground and provides
 
structural support and shelter/protection for the condenser circulating water system vacuum
 
breaker components. These components prevent ba ckflow from the warm water channel into the intake channel. This ensures that the maximum temperature analysis assumptions, for
 
accident cooling systems, are maintained during accidents and events.
The vacuum pipe building contains SR components that are relied upon to remain functional during and following DBEs. The failure of NSR SSCs in the vacuum pipe building could prevent
 
the satisfactory accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides structural support and shelter/protection for SR and NSR components
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support for structures and components within the scope of license renewal
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.3.4, the applicant identified the following vacuum pipe building component types that are within the scope of license renewal and subject to an AMR:
* hatches and plugs
* electrical and I&C penetrations
* mechanical penetrations
* reinforced concrete beams, columns, walls, and slabs 2.4.3.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.3.4 and UFSAR Section 12.2.7.8.3 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.3.4 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
2-171 In RAI 2.4-9(b), dated December 20, 2004, the staff stated that LRA Section 2.4.3 lists several structures that are not shown in drawing 0-10E201-01-LR. Therefore, the staff requested the
 
applicant to describe the specific location of the vacuum pipe building and confirm that there are
 
no items such as structural steel embedments, carbon steel boltings, reinforced concrete
 
foundation footings, grouted concrete, compressible joints and seals, waterproofing membrane
 
and caulking materials that require an AMR.
In its response, by letter dated January 24, 2005, the applicant stated:
The vacuum pipe building is an underground structure accessed through a manhole and contains the condenser circulating water system vacuum breaker components that
 
prevent back flow from the warm water channel to the intake channel (Reference
 
UFSAR 12.2.7.8.3). The vacuum pipe building is an underground structure located
 
south-east of the plant administration building as depicted on TVA drawing 0-10E201-01
 
and LR drawing 0-10E201-01-LR. The following components are also located in the
 
vacuum pipe building and are evaluated as structures and component supports
 
commodities in LRA Section 2.4.8:
* Conduit and Supports
* Electrical Panels, Racks, Cabinets, and Other Enclosures
* Non-ASME Equivalent Supports and Components The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the components also include support structural members, welds, bolting, anchorage and building
 
concrete at anchorage (including base plate and grout) to the structure. Waterproofing
 
membranes are not relied upon to support the intended functions of the structural components
 
of BFN structures.
The staff found that the applicant had adequately responded to RAI 2.4-9(b) concerning the vacuum pipe building structure. Therefore, the staff's concern described in RAI 2.4-9(b) is
 
resolved.2.4.3.4.3  Conclusion
 
The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
vacuum pipe building components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the vacuum pipe building components that are subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2-172 2.4.3.5  Residual Heat Removal Service Water Tunnels 2.4.3.5.1  Summary of Technical Information in the Application In LRA Section 2.4.3.5, the applicant described the RHRSW tunnels. The RHRSW tunnels are underground, multi-plate, arch tunnels that protect SR piping systems. This includes the
 
RHRSW and EECW supply and discharge piping that penetrates the south wall of the reactor
 
building and is buried, below grade, near the south end of the tunnel.
The failure of an NSR SSC in the RHRSW tunnel could prevent the satisfactory accomplishment of an SR function. The RHRSW tunnel also performs functions that support fire protection.
The intended functions within the scope of license renewal include the following:
* provides structural support and shelter/protection for SR and NSR components, and components that are relied upon to demonstrate compliance with the fire protection
 
regulated event
* prevents debris from entering a system or component
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.3.5, the applicant identified the following RHRSW tunnel component types that are within the scope of license renewal and subject to an AMR:
* compressible joints and seals
* electrical and I&C penetrations
* piles
* tunnels 2.4.3.5.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.3.5 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with the guidance described in
 
SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not
 
omitted from the scope of license renewal any components with intended functions delineated
 
under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had
 
identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2-173 The staff's review of LRA Section 2.4.3.5 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4-9(c), dated December 20, 2004, the staff stated that LRA Section 2.4.3, Class 1 Group 3 Structures, lists several BFN structures that are not shown in drawing 0-10E201-01-LR.
 
Therefore, the staff requested the applicant to describe the specific location of the RHRSW
 
tunnels including their embedded boundaries in drawing 0-10E201-01-LR. The staff also
 
requested the applicant to identify, as appropriate, items requiring an AMR that are part of the
 
service water tunnels, such as structural steel embedments, carbon steel boltings, reinforced
 
concrete beams, walls, slabs and foundation footings, grouted concrete, mechanical
 
penetrations, waterproofing membrane and caulking materials.
In its response, by letter dated January 24, 2005, the applicant stated:
The RHRSW tunnels are underground multi-plate arch tunnels that are buried in the earth berm. The north end of the tunnel terminates at the south wall of the reactor
 
building. The south end of the tunnel is open to the outside on the south end of the earth
 
berm. There are two tunnels for each reactor building. The following components are
 
also located in the RHRSW tunnels and are evaluated as structures and component
 
supports commodities in LRA Section 2.4.8:
* ASME Equivalent Supports and Components
* Conduit and Supports
* Electrical Panels, Racks, Cabinets, and Other Enclosures
* Non-ASME Equivalent Supports and Components The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the components also include support structural members, welds, bolting, anchorage and building
 
concrete at anchorage (including base plate and grout) to the structure. Waterproofing
 
membranes are not relied upon to support the intended functions of the structural components
 
of BFN structures.
The staff found that the applicant had adequately responded to RAI 2.4-9(c) related to the RHRSW structure. Therefore, the staff's concern described in RAI 2.4-9(c) is resolved.
2.4.3.5.3  Conclusion
 
The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
RHRSW tunnels components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the RHRSW tunnels components that are subject to an AMR, as required
 
by 10 CFR 54.21(a)(1).
2-174 2.4.3.6  Electrical Cable Tunnel from the Intake Pumping Station to the Powerhouse 2.4.3.6.1  Summary of Technical Information in the Application In LRA Section 2.4.3.6, the applicant described the electrical cable tunnel from the intake pumping station to the powerhouse, which is a Class I structure. The structure is an
 
underground, concrete-encased tunnel that provides structural support and shelter/protection
 
for power cables. These power cables are intended for components in the intake pumping
 
station and include the RHRSW system, EECW sy stem, and electric fire pumps. The tunnel runs east-west under the southern portion of the turbine buildings.
The electrical cable tunnel from the intake pumping station to the powerhouse structure contains SR components that are relied upon to remain functional during and following DBEs.
 
The failure of NSR SSCs in the electrical cable tunnel from the intake pumping station to the
 
powerhouse structure could prevent the satisfactory accomplishment of an SR function. In
 
addition, the electrical cable tunnel from the intake pumping station to the powerhouse structure
 
performs functions that support fire protection.
The intended functions within the scope of license renewal include the following:
* provides structural support and shelter/protection for SR and NSR components, and components that are relied upon to demonstrate compliance with the fire protection
 
regulated event
* provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of the plant
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support for structures and components within the scope of license renewal In LRA Table 2.4.3.6, the applicant identified the following electrical cable tunnel component types that are within the scope of license renewal and subject to an AMR:
* fire barrier
* electrical and I&C penetrations
* tunnels The electrical cable tunnel from the intake pumping station to the powerhouse is an underground concrete-encased tunnel that provides structural support and shelter/protection
 
for the power cables for components (inc luding the RHRSW System, EECW System, and the electric fire pumps) in the intake pumping station. The tunnel also runs east-west under
 
the southern portion of the turbine buildings.
2.4.3.6.2  Staff Evaluation 2-175 The staff reviewed LRA Section 2.4.3.6 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with the guidance described in
 
SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not
 
omitted from the scope of license renewal any components with intended functions delineated
 
under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had
 
identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.3.6 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4-9(d), dated December 20, 2004, the staff stated that LRA Section 2.4.3, Class 1 Group 3 Structures, lists several structures that are not shown in drawing 0-10E201-01-LR.
 
Therefore, the staff requested the applicant to describe the specific locations of the electrical
 
cable tunnel from the intake pumping station to the powerhouse, including the portion running
 
east-west under the southern portion of the turbine buildings. The staff also requested the
 
applicant to identify items such as structural steel embedments, carbon steel boltings, reinforced concrete beams, walls, slabs, and foundation footings, grouted concrete, mechanical
 
penetrations, and waterproofing membrane and caulking materials that require an AMR.
In its response, by letter dated January 24, 2005, the applicant stated:
The Electrical Cable Tunnel is an underground concrete encased tunnel that runs from the northwest corner of the Intake Pumping Station (IPS) to the southeast corner of the
 
unit 3 Turbine Building and then east-west along the southern portion of the BFN
 
Turbine Building. The following components are also located in the Electrical Cable
 
Tunnel and are evaluated as Structures and Component Supports commodities in LRA
 
Section 2.4.8:
* Cable Trays and Supports
* Conduit and Supports
* Electrical Panels, Racks, Cabinets, and Other Enclosures The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the components also include support structural members, welds, bolting, anchorage and building
 
concrete at anchorage (including base plate and grout) to the structure. Waterproofing
 
membranes are not relied upon to support the intended functions of the structural components
 
of BFN structures.
The staff found that the applicant had adequately responded to RAI 2.4-9(d) related to the electrical cable tunnel structure. Therefore, the staff's concern described in RAI 2.4-9(d) is
 
resolved.
2-176 2.4.3.6.3  Conclusion The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
electrical cable tunnel components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the electrical cable tunnel components that are subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.4.3.7  Underground Concrete Encased Structures 2.4.3.7.1  Summary of Technical Information in the Application In LRA Section 2.4.3.7, the applicant described the underground concrete encased structures.
The underground concrete encased structures include SR manholes, handholes and duct banks
 
that span between the SR structures, manholes, and handholes. This group of structures also
 
includes those manholes, handholes, and duct banks that are required to support the SBO
 
regulated event.
The underground concrete encased structures contain SR components that are relied upon to remain functional during and following DBEs. The failure of NSR SSCs in the underground
 
concrete encased structures could prevent the satisfactory accomplishment of an SR function.
 
In addition, the underground concrete encased structures performs functions that support fire
 
protection and SBO.
The intended functions within the scope of license renewal include the following:
* provides structural support and shelter/protection for SR and NSR components, and components that are relied upon to demonstrate compliance with the fire protection and
 
SBO regulated events
* provides flood protection barrier for internal and external flooding events
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support for structures and components within the scope of license renewal
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.3.7, the applicant identified the following underground concrete encased structures component types that are within the scope of license renewal and subject to an AMR:
* caulking and sealants
* duct banks, manholes
* electrical and I&C penetrations 2-177
* penetrations, mechanical 2.4.3.7.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.3.7 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with the guidance described in
 
SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not
 
omitted from the scope of license renewal any components with intended functions delineated
 
under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had
 
identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.3.7 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below In RAI 2.4-9(e), dated December 20, 2004, the staff stated that LRA Section 2.4.3, Class 1 Group 3 structures lists several BFN structures on page 2.4-12 that are not shown in drawing
 
0-10E201-01-LR. Therefore, the staff requested the applicant to list the in-scope structures that
 
have one or more of the underground concrete encased structures described in LRA
 
Section 2.4.3.7. The staff also requested the applicant to identify items such as structural steel
 
embedments, carbon steel boltings, reinforced concrete walls, slabs and foundation footings, grouted concrete, and waterproofing membrane that require an AMR.
In its response, by letter dated January 24, 2005, the applicant stated :
The in-scope structures described in LRA Section 2.4.3.7 include the following:
  *Safety-related handhole (HH) No. 16, located in the yard area north-west of the Intake Pumping Structure (IPS) and safety-related handhole (HH) No. 26, located
 
in the yard area north-east of the Unit 3 Diesel Generator Building (DGB) and
 
south of Condensate Storage Tanks Nos. 1, 2, and 3.    *Safety-related concrete duct bank (inaccessible) that spans from the Unit 1 & 2 Diesel Generator Building to the Standby Gas Treatment Building, safety-related
 
concrete duct bank (inaccessible) that spans from the IPS to HH No. 16 to HH
 
No. 26 and to the Electrical Cable Tunnel from the IPS to the Powerhouse, SR
 
concrete duct bank (inaccessible) that spans from the unit 3 Diesel Generator
 
Building to the Electrical Cable Tunnel from the IPS to the Powerhouse, and the
 
safety-related concrete duct bank (inaccessible) that spans from the Containment
 
Atmosphere Dilution Storage Tank's A and B foundations to the Reactor Building.  *Manholes A and B which provide access to the concrete tunnel located in the 161 kV and 500 kV Switchyards that support the 10 CFR 54.4(a)(3) SBO
 
regulated event. NOTE: The concrete tunnel located in the 161 kV and 500 kV 2-178 switchyards is within the scope of license renewal and identified in LRA ections 2.4.7.5 and 2.4.7.6, respectively, as component type tunnels.  *Handholes 1 - 13 and associated duct banks (inaccessible) located in the transformer yard on the north side of the Turbine Building that support the
 
10 CFR 54.4(a)(3) SBO regulated event.  *The following components are also located in the Underground Concrete Encased Structures and are evaluated as Structures and Component Supports
 
commodities in LRA Section 2.4.8:  - Cable Trays and Supports  - Conduit and Supports
  - Electrical Panels, Racks, Cabinets, and Other Enclosures
  - Non-ASME Equivalent Supports and Components The applicant also noted that for in-scope components evaluated in LRA Section 2.4.8, the components also include support structural members, welds, bolting, anchorage and building
 
concrete at anchorage (including base plate and grout) to the structure. Waterproofing
 
membranes are not relied upon to support the intended functions of the structural components
 
of BFN structures.
The staff found that the applicant had adequately responded to RAI 2.4-9(e) related to underground concrete encased structures. Therefore, the staff's concern described in
 
RAI 2.4-9(e) is resolved.
2.4.3.7.3  Conclusion
 
The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
underground concrete encased structures components that are within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and the underground concrete encased structures
 
components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.3.8  Earth Berm 2.4.3.8.1  Summary of Technical Information in the Application In LRA Section 2.4.3.8, the applicant described the earth berm. The earth berm is classified as an SR earthen embankment and is common to BFN. The earth berm extends along the west, south, and east walls of the reactor building from the Unit 1 DG building to the Unit 3 DG
 
building. The equipment access lock, the RHRSW tunnels, the vent vaults, and the SGT
 
building are all located within the earth berm.
The earth berm contains SR components that are relied upon to remain functional during and following DBEs.
2-179 The intended function, within the scope of license renewal, is to provide structural and functional support for in-scope structures and features.
In LRA Table 2.4.3.8, the applicant identified the following earth berm component type that is within the scope of license renewal and subject to an AMR:
* intake canals, dikes, embankments
 
2.4.3.8.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.3.8 and UFSAR Sections 12.2.9 and 12.2.10 using the evaluation methodology described in SER Section 2.4. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.4.3.8.3  Conclusion
 
The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the earth berm components
 
that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the earth berm
 
components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
Section 2.4.3.9. In earlier RAI 2.4-1 response, dated January 24, 2005, the applicant stated that the south access retaining walls were inadvertently omitted. The retaining walls are SR
 
structural features that maintain the stability of the earth berm, therefore are included in the
 
scope of license renewal. In Attachment 2 to its letter, the applicant added LRA Section 2.4.3.9, as discussed below.
2.4.3.9  South Access Retaining Walls In added LRA Section 2.4.3.9, the applicant described the south access retaining walls. The south access retaining walls are required to support the existing earth berm for the construction
 
of a new temporary access building. This access building will allow Unit 1 recovery personnel
 
entry into the Unit 1 reactor building during the recovery of Unit 1. These retaining walls have
 
been classified as SR to match the safety function of the earth berm. These retaining walls are
 
located east of the equipment access lock.
2-180 The south access retaining walls contain SR components that are relied upon to remain functional during and following DBEs.
The intended function, within the scope of license renewal, is to provide structural and functional support, for in-scope structures and components, by an SR component.
In added LRA Table 2.4.3.9, the applicant identified the reinforced concrete beams, columns, walls, and slabs component type that is within the scope of license renewal and subject to an
 
AMR.2.4.3.9.2  Staff Evaluation
 
The staff reviewed added LRA Section 2.4.3.9 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with the guidance described in
 
SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the added section of the LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that
 
the applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.4.3.9.3  Conclusion
 
The staff reviewed the added LRA Section 2.4.3.9 and related structural/component information to determine whether any SSCs that should be within the scope of license renewal were not
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR were not
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
south access retaining walls components that are within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and that the applicant had adequately identified the south access
 
retaining walls components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
====2.4.4 Class====
1 Group 6 Structures In LRA Section 2.4.4, the applicant identified the structures and components of the Class 1 Group 6 structures that are subject to an AMR for license renewal.
The applicant described the supporting structures and components of the Class 1 Group 6 structures in the following sections of the LRA:
* 2.4.4.1intake pumping station
* 2.4.4.2gate structure No. 3
* 2.4.4.3intake channel
* 2.4.4.4north bank of cool water channel east of gate structure No. 2
* 2.4.4.5south dike of cool water channel between gate structure Nos. 2 and 3 2-181 The corresponding subsections of the SER, 2.4.4.1 - 2.4.4.5, present the staff's review findings with respect to the Class 1 Group 6 structures.
2.4.4.1  Intake Pumping Station 2.4.4.1.1  Summary of Technical Information in the Application In LRA Section 2.4.4.1, the applicant described the intake pumping station, which is a Class 1 structure constructed of reinforced concrete. The intake pumping station houses components
 
for BFN and provides structural support and shelter/protection for the condenser circulating
 
water pumps, the electric fire pumps, and the pumps that supply the RHRSW and the EECW
 
systems. The station also protects SR equipment and components, such as the pumps supplying the RHRSW and EECW systems, from design-basis events such as earthquakes, floods, and tornadoes.
The intake pumping station contains SR components that are relied upon to remain functional during and following DBEs. The failure of NSR SSCs in the intake pumping station could
 
prevent the satisfactory accomplishment of an SR function. In addition, the intake pumping
 
station performs functions that support fire protection and SBO.
The intended functions within the scope of license renewal include the following:
* provides structural support and shelter/protection for SR and NSR components, and components relied upon to demonstrate compliance with the fire protection and SBO
 
regulated events
* provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of the plant
* provides a flood protection barrier for internal and external flooding events
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support for structures and components within the scope of license renewal
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.4.1, the applicant identified the following intake pumping station component types that are within the scope of license renewal and subject to an AMR:
* caulking and sealants
* compressible joints and seals
* controlled leakage doors
* fire barriers
* masonry block
* electrical and I&C penetrations
* mechanical penetrations
* reinforced concrete beams, columns, walls, and slabs 2-182
* structural steel beams, columns, plates, and trusses 2.4.4.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.4.1 and UFSAR Sections 12.2.7 and 12.2.16 using the evaluation methodology described in SER Section 2.4. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.4.1 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4-10(a), dated December 20, 2004, the staff requested the applicant to provide additional information regarding the intake pumping station structure. Specifically, the RAI
 
requested the applicant to identify, as applicable, items such as hatches and plugs, structural
 
steel embedments, carbon steel boltings, reinforced concrete foundation footings, grouted
 
concrete, and waterproofing membrane materials that require an AMR.
In its response, by letter dated January 24, 2005, the applicant stated:
The following components are also located in the intake pumping station and are evaluated as structures and component supports commodities in LRA Section 2.4.8:
* ASME Equivalent Supports and Components
* Cable Trays and Supports
* Conduit and Supports
* Electrical Panels, Racks, Cabinets, and Other Enclosures
* Equipment Supports and Foundations
* Instrument Line Supports
* Non-ASME Equivalent Supports and Components
* Stairs, Platforms, Grating Supports
* Tube Track The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the components also include support structural members, welds, bolting, anchorage and building
 
concrete at anchorage (including base plate and grout) to the structure. Waterproofing
 
membranes are not relied upon to support the intended functions of the structural components
 
of BFN structures.
2-183 The staff found that the applicant had adequately responded to RAI 2.4-10(a) related to the intake pumping station structure. Therefore, the staff's concern described in RAI 2.4-10(a) is
 
resolved.2.4.4.1.3  Conclusion
 
The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
intake pumping station components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the intake pumping station components that are subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.4.4.2  Gate Structure No. 3 2.4.4.2.1  Summary of Technical Information in the Application In LRA Section 2.4.4.2, the applicant described the gate structure No. 3, which is a Class 1 structure common to all three of the units. The structure acts as a skimmer wall for water drawn
 
from Wheeler Reservoir and used in the plant for cooling. Gate structure No 3 is designed so
 
that a sufficient flow of water from Wheeler Reservoir is provided to the intake channel, in order
 
to supply the RHRSW and the EECW systems. Gate structure No. 3 is located at the southeast
 
end of the plant, below the intake pumping station and the intake channel.
Gate structure No. 3 contains SR components that are relied upon to remain functional during and following DBEs. In addition, gate structure No. 3 performs functions that support fire
 
protection and SBO.
The intended functions within the scope of license renewal include the following:
* ensures a source of cooling water to SR components
* ensures a source of cooling water to components relied upon to demonstrate compliance with the fire protection and SBO events
* provides for flow distribution
* provides structural and functional support for structures and components within the scope of license renewal In LRA Table 2.4.4.2, the applicant identified the following gate structure No. 3 component types that are within the scope of license renewal and subject to an AMR:
* piles
* reinforced concrete beams, columns, walls, and slabs
* structural steel beams, columns, plates, and trusses 2-184 2.4.4.2.2  Staff Evaluation The staff reviewed LRA Section 2.4.4.2 and UFSAR Sections 11.6 and 12.2.7 using the evaluation methodology described in SER Section 2.4. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.4.4.2.3  Conclusion
 
The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the gate structure No. 3
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the gate structure No. 3 components that are subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.4.4.3  Intake Channel 2.4.4.3.1  Summary of Technical Information in the Application In LRA Section 2.4.4.3, the applicant described the intake channel, which is common to all three units and provides an excavated channel that extends from the intake pumping station to the
 
river channel that would exist if the Wheeler Dam failed. The channel provides a source of water
 
to the condenser circulating water system and the other plant cooling systems during normal
 
operation. The channel also provides a source of cooling water, post-transient and
 
post-accident, for decay heat removal, containment cooling, spent fuel cooling, control bay
 
cooling, essential equipment cooling, and fire protection. In addition, the channel can provide
 
sufficient flow and heat sink capacity to maintain a safe shutdown following a failure of the
 
downstream Wheeler Dam.
The intake channel contains SR components that are relied upon to remain functional during and following DBEs. In addition, the intake channel performs functions that support fire
 
protection and SBO.
The intended functions within the scope of license renewal include the following:
* ensures a source of cooling water to SR components 2-185
* ensures a source of cooling water to components relied upon to demonstrate compliance with the fire protection and SBO events
* provides a source of cooling water
* provides structural and functional support for structures and components within the scope of license renewal In LRA Table 2.4.4.3, the applicant identified the following intake channel component type that is within the scope of license renewal and subject to an AMR:
* intake canals, dikes, embankments
 
2.4.4.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.4.3 and UFSAR Sections 2.4.2 and 12.2.7 using the evaluation methodology described in SER Section 2.4. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.4.4.3.3  Conclusion
 
The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the intake channel
 
components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
the intake channel components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.4.4  North Bank of the Cool Water Channel East of Gate Structure No. 2 2.4.4.4.1  Summary of Technical Information in the Application In LRA Section 2.4.4.4, the applicant described the north bank of the cool water channel east of gate structure No. 2. The structure is an earthen embankment that is located on the north side
 
of the cool water channel and south of the reactor buildings. The structure is SR, with a sloped
 
portion protected by vegetation and rock rip-rap. The bank is designed to protect the buried
 
RHRSW system discharge piping that is located within the bank that discharges into the
 
Wheeler Reservoir.
2-186 The north bank of the cool water channel east of gate structure No. 2 contains SR components that are relied upon to remain functional during and following DBEs. In addition, the structure
 
performs functions that support fire protection and SBO.
The intended functions within the scope of license renewal include the following:
* provides for structural support of the buried SR components, namely piping, and components relied upon to demonstrate compliance with the fire protection and SBO
 
regulated events
* provides structural and functional support for structures and components within the scope of license renewal In LRA Table 2.4.4.4, the applicant identified the following component type in the north bank of the cool water chanel east of gate structure No. 2 that is within the scope of license renewal and
 
subject to an AMR:
* intake canals, dikes, embankments
 
2.4.4.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.4.4 and UFSAR Section 12.2.7 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.4.4.4.3  Conclusion
 
The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the components of the north
 
bank of the cool water channel east of gate structure No. 2 that are within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and the components of the north bank of the cool
 
water channel east of gate structure No. 2 that are subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2-187 2.4.4.5  South Dike of Cool Water Channel between Gate Structure Nos. 2 and 3 2.4.4.5.1  Summary of Technical Information in the Application In LRA Section 2.4.4.5, the applicant described the south dike of the cool water channel between gate structure Nos. 2 and 3. The structure is an earthen dike that is located on the
 
south side of the cool water channel and forms a boundary with the Wheeler Reservoir on the
 
north side. The dike is an SR earthen structure that has a sloped portion that is protected with
 
vegetation and rock rip-rap. The dike is designed to protect the buried RHRSW system
 
discharge piping that is located within the dike and that discharges into Wheeler Reservoir.
The portions of the south dike of cool water channel between gate structure Nos. 2 and 3 structure containing components subject to an AMR are those portions located above the
 
RHRSW system discharge piping.
The south dike of the cool water channel between gate structure Nos. 2 and 3 contains SR components that are relied upon to remain functional during and following DBEs. In addition, the
 
dike performs functions that support fire protection and SBO.
The intended functions within the scope of license renewal include the following:
* provides structural support of buried SR components, namely piping, and components relied upon to demonstrate compliance with the fire protection and SBO regulated
 
events
* provides structural and functional support for structures and components within the scope of license renewal In LRA Table 2.4.4.5, the applicant identified the following component types in the south dike of cool water channel between gate structure Nos. 2 and 3 that are within the scope of license
 
renewal and subject to an AMR:
* intake canals, dikes, embankments
 
2.4.4.5.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.4.5 and UFSAR Section 12,2.7 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2-188 The staff's review of LRA Section 2.4.4.5 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4-6, dated December 20, 2004, the staff stated that the LRA Section 2.4.4.5 states that the portion of the structure that contains components requiring an AMR is the portion above the
 
RHRSW system discharge piping. Therefore, the staff requested applicant to clarify if the entire
 
south dike of cooling water channel between gate structure Nos. 2 and 3, or only the portion
 
indicated, is designated to be within the scope requiring an AMR. The staff also stated that, if
 
the applicant scoped only a portion of the south dike structure as requiring an AMR, the staff
 
wanted the applicant to discuss the basis for narrowing the scope. The staff required the
 
applicant to clearly define the boundary within the AMR scope.
In its response, by letter dated January 24, 2005, the applicant stated:
Only the portion of the south dike of the cool water channel between gate structure Nos.
 
2 and 3 above the RHRSW discharge piping system plus approximately 30 feet on either
 
side of the piping is within the scope of License Renewal and requires an AMR. The
 
earthen dike provides a structural support intended function as noted in LRA
 
Table 2.4.4.5 for the RHRSW discharge piping system and that portion of the dike has
 
been qualified for a seismic event.
The staff found the above clarification provided by the applicant adequate and acceptable. The staff's concern described in RAI 2.4-6 is resolved.
2.4.4.5.3  Conclusion
 
The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
components in the south dike of the cool water channel between gate structure Nos. 2 and 3
 
that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the
 
components in the south dike of the cool water channel between gate structure Nos. 2 and 3
 
that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
====2.4.5 Class====
1 Group 8 Structures In LRA Section 2.4.5, the applicant identified the structures and components of the Class 1 Group 8 structures that are subject to an AMR for license renewal.
The applicant described the supporting structures and components of the Class 1 Group 8 structures in the following sections of the LRA:
* 2.4.5.1condensate water storage tanks' foundations and trenches
* 2.4.5.2containment atmosphere dilution storage tanks' foundations 2-189 The corresponding subsections of the SER 2.4.5.1 - 2.4.5.2, present the staff's review findings with respect to the Class 1 Group 8 structures for BFN.
2.4.5.1  Condensate Water Storage Tanks' Foundations and Trenches 2.4.5.1.1  Summary of Technical Information in the Application In LRA Section 2.4.5.1, the applicant described the condensate water storage tanks' foundations and trenches. The condensate water storage tanks' foundations and trenches are a
 
shared feature for BFN. Five 500,000-gallon capacity tanks are supported on reinforced
 
concrete ring foundations or on reinforced concrete slabs, on grade, with a sand bed. Only
 
condensate water storage tank Nos. 1, 2, and 3 are within the scope of license renewal.
 
Therefore, the foundations, trenches, and components for these tanks are also within the scope
 
of license renewal.
The condensate water storage tanks' foundations and trenches are concrete structures that provide structural support to ensure that the condensate water storage tanks can provide: (1) a
 
source of water makeup to the condenser hotwells and the CRD hydraulic system, during
 
normal operations; (2) high purity water for miscellaneous makeup uses throughout the plant (e.g., demineralizer backwash and spent fuel pool makeup); and (3) a source of clean water to
 
the HPCI and RCIC systems, when required for test; for reactor vessel makeup during accidents
 
and regulated events; and to the core spray systems, when required for test.
The foundations and trenches for the three condensate water storage tanks that provide the normal water supply to the units, contain components requiring an AMR.
The condensate water storage tanks' foundations and trenches contain SR components that are relied upon to remain functional during and following DBEs. In addition, the condensate water
 
storage tanks' foundations and trenches perform functions that support fire protection and SBO.
The intended functions within the scope of license renewal include the following:
* provides physical support and shelter/protection for components that are relied upon to demonstrate compliance with the fire protection and SBO regulated events
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support for structures and components within the scope of license renewal
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.5.1, the applicant identified the following condensate water storage tanks' foundations and trenches component types that are within the scope of license renewal and
 
subject to an AMR:
* equipment supports and foundations
* electrical and I&C penetrations 2-190
* mechanical penetrations
* structural steel beams, columns, plates, and trusses
* trenches 2.4.5.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.5.1 and UFSAR Section 11.9 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.5.1 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4-10(b), dated December 20, 2004, the applicant was asked to provide additional information regarding the condensate water storage tank's foundation and trenches. The staff
 
also requested the applicant to confirm that the equipment supports and foundations as well as
 
the trenches listed in LRA Table 2.4.5.1 consist of reinforced concrete components and to
 
identify items such as structural steel embedments, carbon steel boltings, grouted concrete, and
 
waterproofing membrane materials that require an AMR.
In its response, by letter dated January 24, 2005, the applicant stated:
Regarding the Condensate Water Storage Tank's Foundation and Trenches, "Equipment Supports and Foundations" as well as "Trenches" components listed in Table 2.4.5.1
 
consist of reinforced concrete and this is confirmed in Table 3.5.2.17 of the LRA. Note
 
that the Condensate Storage Tanks are supported on a reinforced concrete ring
 
foundation and the earthen fill material (rock and sand) inside the ring is identified as
 
Item 1 of Table 3.5.2.17. The following components are also located on the Condensate
 
Water Storage Tanks Foundations and Trenches and are evaluated as Structures and
 
Component Supports commodities in LRA Section 2.4.8:
* Conduit and Supports
* Electrical Panels, Racks, Cabinets, and Other Enclosures
* Instrument Racks, Frames, Panels, & Enclosures
* Non-ASME Equivalent Supports and Components The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the components also include support structural members, welds, bolting, anchorage and building
 
concrete at anchorage (including base plate and grout) to the structure. Waterproofing 2-191 membranes are not relied upon to support the intended functions of the structural components of BFN structures.
The staff found that the applicant had adequately responded to RAI 2.4-10(b) related to the condensate water storage tanks' foundations and trenches structures. Therefore, the staffs
 
concern described in RAI 2.4-10(b) is resolved.
2.4.5.1.3  Conclusion
 
The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
condensate water storage tanks' foundations and trenches components that are within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and the condensate water storage
 
tanks' foundations and trenches components that are subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.4.5.2  Containment Atmosphere Dilution Storage Tanks' Foundations 2.4.5.2.1  Summary of Technical Information in the Application In LRA Section 2.4.5.2, the applicant described the CAD storage tanks' foundations. The tanks' foundations are reinforced concrete slabs on grade, or foundations, that provide structural
 
support for the tanks. These tanks are used by the CAD system to control the concentration of
 
combustible gases in the primary containment after an accident, and to provide a backup
 
pneumatic supply to selected components when the control air system is unavailable.
The CAD system storage tanks' foundations contain SR components that are relied upon to remain functional during and following DBEs. In addition, the CAD storage tanks' foundations
 
perform functions that support fire protection and SBO.
The intended functions within the scope of license renewal include the following:
* provides structural support for SR components and components relied upon to demonstrate compliance with the fire protection and SBO regulated events
* provides structural and functional support for structures and components within the scope of license renewal In LRA Table 2.4.5.2, the applicant identified the following CAD storage tanks' foundations component types that are within the scope of license renewal and subject to an AMR:
* equipment supports and foundations.
2-192 2.4.5.2.2  Staff Evaluation The staff reviewed LRA Section 2.4.5.2 and UFSAR Section 5.2.6 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.5.2 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4-7, dated December 20, 2004, the staff stated that in LRA Section 2.4.5.2, the applicant discussed the screening results of the CAD storage tank's foundations. Therefore, for
 
items included in LRA Table 2.4.5.2, the staff requested the applicant to identify other items that
 
require an AMR, such as structural steel embedments, carbon steel boltings, reinforced
 
concrete slabs and foundation footings, and grouted concrete.
In its response, by letter dated January 24, 2005, the applicant stated:
The reinforced concrete foundation slab for the Containment Atmosphere Dilution (CAD)
Storage Tank's Foundation is included as part of the "Equipment Supports and
 
Foundation" component type in Table 2.4.5.2. CAD Storage Tank's Foundation is a
 
reinforced concrete foundation slab on grade that provides structural support for the tank
 
of the CAD system.
The following components are also located on the CAD storage tank foundation and are evaluated as part of the structures and component supports commodity group in LRA
 
Section 2.4.8:
* Electrical Panels, Racks, Cabinets, and Other Enclosures
* Conduits and Supports
* Non-ASME Equivalent Supports and Components
* Instrument Racks, Frames, Panels, & Enclosures The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the components also include support structural members, welds, bolting, anchorage and building
 
concrete at anchorage (including base plate and grout) to the structure.
The staff found that the response adequately clarified LRA Section 2.4.5.2. Therefore, the staff's concern described in RAI 2.4-7 is resolved.
2-193 2.4.5.2.3  Conclusion The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
CAD storage tanks' foundations components that are within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and the CAD storage tanks' foundations components that are
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
====2.4.6 Class====
1 Group 9 Structures 2.4.6.1  Reinforced Concrete Chimney 2.4.6.1.1  Summary of Technical Information in the Application In LRA Section 2.4.6.1, the applicant described the reinforced concrete chimney structure, which is a Class 1 structure that serves all three units. The chimney is 600 feet in elevation and
 
provides an elevated release point for radioacti ve gases. These radioactive gases are released from the gaseous radwaste processing system s during normal plant operations. They are also released from the SGT system during secondar y containment isolation and during primary containment venting. The hardened wetwell vent systems also release gaseous radwaste, following design-basis accidents. The system is designed so that Class 1 structures (with the
 
exception of the off-gas treatment building) will not be damaged during DBEs.
The reinforced concrete chimney contains SR components that are relied upon to remain functional during and following DBEs. The failure of NSR SSCs in the reinforced concrete
 
chimney could prevent the satisfactory accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* provides structural support and shelter/protection for SR and NSR components
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support for structures and components within the scope of license renewal
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.6.1, the applicant identified the following reinforced concrete chimney component types that are within the scope of license renewal and subject to an AMR:
* hatches and plugs
* metal roofing
* electrical and I&C penetrations 2-194
* mechanical penetrations
* reinforced concrete beams, columns, walls, and slabs
* roofing membrane
* structural steel beams, columns, plates, and trusses 2.4.6.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.6.1 and UFSAR Section 12.2.4 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.4.6.1.3  Conclusion
 
The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff performed a review to determine whether any
 
components that should be subject to an AMR had not been identified by the applicant. No
 
omissions were identified. On the basis of its review, the staff concluded that there is
 
reasonable assurance that the applicant had adequately identified the reinforced concrete
 
chimney components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the reinforced concrete chimney components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.7  Non-Class 1 Structures In LRA Section 2.4.7, the applicant identified the structures and components of the non-Class 1 structures that are subject to an AMR for license renewal.
The applicant described the supporting structures and components of the non-Class 1 structures in the following sections of the LRA:
* 2.4.7.1Turbine Buildings
* 2.4.7.2Diesel High Pressure Fire Pump House
* 2.4.7.3Vent Vault
* 2.4.7.4Transformer Yard
* 2.4.7.5161 kV Switchyard
* 2.4.7.6500 kV Switchyard
* 2.4.7.7Isolation Valve Pits (added LRA Section)
* 2.4.7.8Radwaste Building (added LRA Section)
* 2.4.7.9Service Building (added LRA Section) 2-195 The corresponding subsections of the SER, 2.4.7.1 - 2.4.7.6, present the staff's review findings with respect to the non-Class 1 structures for BFN.
2.4.7.1  Turbine Buildings 2.4.7.1.1  Summary of Technical Information in the Application In LRA Section 2.4.7.1, the applicant described the turbine buildings. The turbine buildings are a common Class II structure that consist of a reinforced concrete structure with a steel
 
superstructure. The buildings are compartmentalized; the primary consideration for the design
 
of the walls within the buildings is for radiation shielding. The turbine buildings provide structural
 
support and shelter/protection for components required for safe shutdown following the SBO
 
and fire protection regulated events. The buildings also provide support and shelter/protection
 
for the outboard main steam isolation valves leakage pathway to condenser.
The failure of NSR SSCs in the turbine buildings could prevent the satisfactory accomplishment of an SR function. The turbine buildings also perform functions that support fire protection and
 
SBO.The intended functions within the scope of license renewal include the following:
* provides structural support and shelter/protection for the outboard main steam isolation valves leakage pathway to condenser
* not adversely impact other Class I structures as a result of a DBE
* provides structural support and shelter/protection for components relied upon to demonstrate compliance with the SBO and fire protection regulated events
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.7.1, the applicant identified the following turbine buildings component types that are within the scope of license renewal and subject to an AMR:
* hatches/plugs
* metal roofing
* masonry block (within scope for Unit 2 only)
* electrical and I&C penetrations
* mechanical penetrations
* piles
* reinforced concrete beams, columns, walls, and slabs
* roof membrane
* structural steel beams, columns, plates and trusses 2-196 2.4.7.1.2  Staff Evaluation The staff reviewed LRA Section 2.4.7.1 and UFSAR Section 12.2.3 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.7.1 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4 -11(a), the applicant was requested to provide additional information regarding the turbine buildings. The staff also requested the applicant to explain the basis for stating that
 
masonry block utilized for Units 1 and 3 is not in scope for the period of extended operation.
 
The staff further requested the applicant to identify items that require an AMR, such as
 
structural steel embedments, carbon steel boltings, grouted concrete, metal sidings, and waterproofing membrane materials.
In a letter dated January 24, 2005, the applicant responded as follows:
The masonry wall in the unit 2 Turbine Building provides a structural NSR support intended function for cable tray supports for cables required to support the off-site AC
 
recovery for SBO requirements. The SBO cables are routed through the unit 2 Turbine
 
Building in a cable gallery with walls constructed of masonry block, to the north end of
 
the unit 2 Turbine Building, and then to a concrete tunnel buried in the yard north of the
 
Turbine Building. The concrete tunnel provides access to the 161 kV and 500kV
 
Switchyards. Only the unit 2 Turbine Building masonry walls are in scope due to the
 
unique cable gallery to tunnel routing of the cables required to support the off-site AC
 
recovery for SBO requirements for all units. This unique cable gallery does not exist in
 
the unit 1 or 3 Turbine Buildings.
The following components are also located in the BFN Turbine Buildings and are evaluated as Structures and Component Supports commodities in LRA section 2.4.8:
* ASME Equivalent Supports and Components
* Cable Trays and Supports
* Conduit and Supports
* Electrical Panels, Racks, Cabinets, and Other Enclosures
* Equipment Supports and Foundations
* Instrument Racks, Frames, Panels, & Enclosures
* Non-ASME Equivalent Supports and Components
* Stairs, Platforms, Grating Supports 2-197 The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the components also include support structural members, welds, bolting, anchorage and building
 
concrete at anchorage (including base plate and grout) to the structure. Waterproofing
 
membranes are not relied upon to support the intended functions of the structural components
 
of BFN structures.
The staff found that the applicant had adequately responded to RAI 2.4 -11(a) related to the turbine buildings structures. Therefore, the concern described in RAI 2.4-11(a) is resolved.
2.4.7.1.3  Conclusion The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
turbine buildings components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the turbine buildings components that are subject to an AMR, as required
 
by 10 CFR 54.21(a)(1).
2.4.7.2  Diesel High Pressure Fire Pump House 2.4.7.2.1  Summary of Technical Information in the Application In LRA Section 2.4.7.2, the applicant described the diesel high pressure fire pump house. The diesel high pressure fire pump house is a shared structure for BFN. The pump house provides
 
structural support and shelter/protection for the diesel high pressure fire pump.
The entire diesel high pressure fire pump house contains components that are subject to an AMR. The diesel high pressure fire pump house performs functions that support fire protection.
The intended functions within the scope of license renewal include the following:
* provides structural support and shelter/protection for components relied upon to demonstrate compliance with the fire protection regulated event
* prevents debris from entering a system or component
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.7.2, the applicant identified the following diesel high pressure fire pump house component types that are within the scope of license renewal and subject to an AMR:
* metal roofing 2-198
* metal siding
* electrical and I&C penetrations
* mechanical penetrations
* piles
* reinforced concrete beams, columns, walls, and slabs
* roof membrane
* structural steel beams, columns, plates, and trusses 2.4.7.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.7.2 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with the guidance described in
 
SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not
 
omitted from the scope of license renewal any components with intended functions delineated
 
under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had
 
identified as being within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.7.2 identified area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4 -11(b), dated December 20, 2004, the staff requested the applicant to identify items that require an AMR, such as structural steel embedments, carbon steel boltings, grouted
 
concrete, and waterproofing membrane materials.
In its response, by letter dated January 24, 2005, the applicant stated:
The following components are also located in the diesel high pressure fire pump house and are evaluated as structures and component supports commodities in LRA section
 
2.4.8:
* Conduit and Supports
* Electrical Panels, Racks, Cabinets, and Other Enclosures
* Equipment Supports and Foundations
* Non-ASME Equivalent Supports and Components The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the components also include support structural members, welds, bolting, anchorage and building
 
concrete at anchorage (including base plate and grout) to the structure. Waterproofing
 
membranes are not relied upon to support the intended functions of the structural components
 
of BFN structures.
 
2-199 The staff found that the applicant had adequately responded to RAI 2.4 -11(b) related to the diesel high pressure fire pressure fire pump house structure. Therefore, the staff's concern
 
described in RAI 2.4-11(b) is resolved.
2.4.7.2.3  Conclusion The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
diesel high pressure fire pump house components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the diesel high pressure fire pump house components that
 
are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.7.3  Vent Vaults 2.4.7.3.1  Summary of Technical Information in the Application In LRA Section 2.4.7.3, the applicant described the vent vaults. A vent vault is provided for each unit. Each vent vault is a concrete structure with an open top. The base foundation for each vent
 
vault is founded on compacted backfill that is located within the earth berm and adjacent to the
 
respective reactor building. The vent vaults contain components required for the reactor building
 
ventilation system supply, including the secondary containment isolation dampers.
The portions of the vent vaults containing components subject to an AMR include the east and west walls and the floor slab. The failure of NSR systems, SSCs in the v ent vaults could prevent the satisfactory accomplishment of an SR function.
The intended function within the scope of license renewal is to provide structural and functional support for in-scope structures and components by an NSR component.
In LRA Table 2.4.7.3, the applicant identified the following vent vaults component types that are within the scope of license renewal and subject to an AMR:
* reinforced concrete beams, columns, walls, and slabs
 
2.4.7.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.7.3 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with the guidance described in
 
SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not
 
omitted from the scope of license renewal any components with intended functions delineated
 
under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had
 
identified as being within the scope of license renewal to verify that the applicant had not 2-200 omitted any passive and long-lived components that should be subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.7.3 identified area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4-9(a), dated December 20, 2004, the staff stated that LRA Section 2.4.3 lists several structures that are not shown in drawing 0-10E201-01-LR. Therefore, the staff requested the
 
applicant to clarify the reason why the three vent vaults shown in drawing 0-10E201-01-LR do
 
not indicate the specific systems or components contained or sheltered within them.
 
Additionally, the applicant was requested to identify items that require an AMR, such as
 
structural steel embedments, carbon steel boltings, grouted concrete, and waterproofing
 
membrane materials.
In its response, by letter dated January 24, 2005, the applicant stated:
The three vent vaults are open-top concrete structures located within the earth berm adjacent to their associated reactor building. The vent vaults contain components
 
required for the reactor building ventilation system supply, including the secondary
 
containment isolation dampers. Other than the "Reinforced Concrete Beams, Columns, Walls and Slabs" noted on LRA Table 2.4.7.3, they contain no components that require
 
an aging management review.
The staff found that the applicant had adequately responded to RAI 2.4-9(a) on the vent vaults structure. Therefore, the staff's concern described in RAI 2.4-9(a) is resolved.
2.4.7.3.3  Conclusion The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
vent vaults components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the vent vaults components that are subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.4.7.4  Transformer Yard 2.4.7.4.1  Summary of Technical Information in the Application In LRA Section 2.4.7.4, the applicant described the transformer yard. The transformer yard is a shared feature for all three units. The transformer yard supports components required for power
 
restoration following the SBO regulated event.
The transformer yard performs functions that support SBO.
2-201 The intended functions within the scope of license renewal include the following:
* provides structural support for components relied upon to demonstrate compliance with the SBO regulated event
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.7.4, the applicant identified the following transformer yard component types that are within the scope of license renewal and subject to an AMR:
* piles
* structural steel beams
* structural columns
* structural plates
* structural trusses 2.4.7.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.7.4 and UFSAR Sections 8.2, 8.4 and 8.10 using the evaluation methodology described in SER Section 2.4. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.7.4 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI, as discussed below.
In RAI 2.4 -11(d), dated December 20, 2004, the staff requested the applicant, with respect to the transformer yard, to identify, items such as structural steel embedments, carbon steel plates
 
and boltings, reinforced concrete pads and footings, grouted concrete, and waterproofing
 
membrane materials that require an AMR.
In its response by letter, dated January 24, 2005, the applicant stated:
The following components are also located in the BFN Transformer Yard, and are evaluated as Structures and Component Supports commodities in LRA section 2.4.8:
* Equipment Supports and Foundations The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the components also include support structural members, welds, bolting, anchorage and building 2-202 concrete at anchorage (including base plate and grout) to the structure. Waterproofing membranes are not relied upon to support the intended functions of the structural components
 
of BFN structures.
The staff found that the applicant had adequately responded to RAI 2.4-11(d) related to the transformer yard structure. Therefore, the staff's concern described in RAI 2.4-11(d) is resolved.
2.4.7.4.3  Conclusion
 
The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
transformer yard components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the transformer yard components that are subject to an AMR, as required
 
by 10 CFR 54.21(a)(1).
2.4.7.5  161 kV Switchyard 2.4.7.5.1  Summary of Technical Information in the Application In LRA Section 2.4.7.5, the applicant described the 161 kV switchyard, which is a shared feature for all three units. The switchyard routes power from offsite transmission lines into BFN
 
for onsite use. The 161 kV switchyard supports components required for power restoration
 
following the SBO regulated event.
The 161 kV switchyard performs functions that support SBO.
 
The intended functions within the scope of license renewal include the following:
* provides structural support and shelter/protection for components that are relied upon to demonstrate compliance with the SBO regulated event
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.7.5, the applicant identified the following 161 kV switchyard component types that are within the scope of license renewal and subject to an AMR:
* structural steel beams
* structural columns
* structural plates
* structural trusses
* tunnels 2-203 2.4.7.5.2  Staff Evaluation The staff reviewed LRA Section 2.4.7.5 and UFSAR Sections 1.5,1.6, 8.1, 8.3, 8.4, and 8.10 using the evaluation methodology described in SER Section 2.4. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.7.5 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4 -11(d)(2), dated December 20, 2004, the staff requested the applicant to identify items that require an AMR, such as structural steel embedments, carbon steel plates and
 
boltings, reinforced concrete pads and footings, grouted concrete, and waterproofing membrane materials.
In its response, by letter January 24, 2005, the applicant stated:
The following components are also located in the BFN 161 kV Switchyard and are evaluated as Structures and Component Supports commodities in LRA section 2.4.8:
* Equipment Supports and Foundations
* Cable Trays and Supports
* Conduit and Supports
* Electrical Panels, Racks, Cabinets, and Other Enclosures The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the components also include support structural members, welds, bolting, anchorage and building
 
concrete at anchorage (including base plate and grout) to the structure. Waterproofing
 
membranes are not relied upon to support the intended functions of the structural components
 
of BFN structures.
The staff found that the applicant had adequately responded to RAI 2.4-11(d) related to the 161 kV switchyard structure. Therefore, the staff's concern described in RAI 2.4-11(d) is resolved.
2.4.7.5.3  Conclusion The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff 2-204 concluded that there is reasonable assurance that the applicant had adequately identified the 161 kV switchyard components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the 161 kV switchyard components that are subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.4.7.6  500 kV Switchyard 2.4.7.6.1  Summary of Technical Information in the Application In LRA Section 2.4.7.6, the applicant described the 500 kV switchyard. The 500 kV switchyard is a shared feature for all three units. The switchyard routes power to offsite transmission lines
 
and can be used to route power into BFN for onsite use. The 500 kV switchyard supports
 
components required for power restoration following an SBO regulated event.
The 500 kV switchyard performs functions that support SBO.
 
The intended functions within the scope of license renewal include the following:
* provides structural support and shelter/protection for components that are relied upon to demonstrate compliance with the SBO regulated event
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support, for in-scope structures and components, by an NSR component In LRA Table 2.4.7.6, the applicant identified the following 500 kV switchyard component types that are within the scope of license renewal and subject to an AMR:
* structural steel beams
* structural columns
* structural plates
* structural trusses
* tunnels 2.4.7.6.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.7.6 and UFSAR Sections 1.5, 1.6, 8.1, 8.3, 8.4, and 8.10 using the evaluation methodology described in SER Section 2.4. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2-205 The staff's review of LRA Section 2.7.4.6 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4-11(d)(3), dated December 20, 2004, the staff requested the applicant to identify items that require an AMR, such as structural steel embedments, carbon steel plates and boltings, reinforced concrete pads and footings, grouted concrete, and waterproofing membrane materials.
In its response, by letter, dated January 24, 2005, the applicant stated:
The following components are also located in the BFN 500 kV Switchyard and are evaluated as Structures and Component Supports commodities in LRA section 2.4.8:
* Equipment Supports and Foundations
* Cable Trays and Supports
* Conduit and Supports
* Electrical Panels, Racks, Cabinets, and Other Enclosures The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the components also include support structural members, welds, bolting, anchorage and building
 
concrete at anchorage (including base plate and grout) to the structure. Waterproofing
 
membranes are not relied upon to support the intended functions of the structural components
 
of BFN structures.
The staff found that the applicant had adequately responded to RAI 2.4-11(d) related to the 500 kV switchyard structure. Therefore, the staff's concern described in RAI 2.4-11(d) is resolved.
2.4.7.6.3  Conclusion The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
500 kV switchyard components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the 500 kV switchyard components that are subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
Section 2.4.7.7. In earlier RAI 2.4-1 response, dated January 24, 2005, the applicant stated that isolation valve pits are Class II NSR structures that provide structural support and shelter
 
protection for the hardened wetwell vent piping and components. Since these isolation valve
 
pits provide an intended function for an in scope mechanical system, therefore, are included
 
within the scope of license renewal. In Attachment 1 to its letter, the applicant added LRA
 
Section 2.4.7.7, as discussed below.
2.4.7.7  Isolation Valve Pits 2-206 2.4.7.7.1  Summary of Technical Information in the Application In added LRA Section 2.4.7.7, the applicant described the isolation valve pits, stating that there is an isolation valve pit for each unit.
The failure of NSR SSCs in the isolation valve pits could potentially prevent the satisfactory accomplishment of an SR function.
The intended functions within the scope of license renewal include the following:
* shelters and protects a component from the effects of weather or localized environmental conditions
* provides structural and functional support, for in-scope structures and components, by an NSR component In added LRA Table 2.4.7.7, the applicant identified the following isolation valve pits component types that are within the scope of license renewal and subject to an AMR:
* caulking & sealants
* penetrations electrical and I&C
* penetrations mechanical
* reinforced concrete beams, columns, walls, and slabs
* structural steel beams, columns, plates, and trusses 2.4.7.7.2  Staff Evaluation
 
The staff reviewed added LRA Section 2.4.7.7 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with the guidance described in
 
SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the added section of the LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that
 
the applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2.4.7.7.3  Conclusion
 
The staff reviewed the added LRA Section 2.4.7.7 and related structural/component information to determine whether any SSCs that should be within the scope of license renewal were not
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR were not
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
isolation valve pits components that are within the scope of license renewal, as required by 2-207 10 CFR 54.4(a), and that the applicant had adequately identified the isolation valve pits components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
Sections 2.4.7.8 and 2.4.7.9
. The staff, in an earlier RAI 2.1-2A(3) dated September 3, 2004, requested additional information related to seismic Class I piping boundaries for identifying
 
additional piping segments and supports/equivalent anchors that need to be placed in the scope
 
of license renewal to satisfy the 10 CFR 54.4(a)(2) criterion. The staff had asked whether if this
 
review brought into scope any new buildings not in the original application. By response dated
 
February 28, 2005, the applicant identified two additional buildings brought into the LRA scope
 
and the added LRA sections are as follows.
2.4.7.8  Radwaste Building 2.4.7.8.1  Summary of Technical Information in the Application In LRA Section 2.4.7.8, the applicant identified the structures and components of the radwaste building that are subject to an AMR for license renewal.
The radwaste building is a cellular box-type c oncrete structure extending approximately 20 feet below grade and 30 feet above grade and supported by steel H-piles driven to bedrock. This
 
building houses services common to all three units. The radwaste building is comprised
 
predominantly of thick walls and slabs, the dimensions of which are determined by shielding
 
requirements. In a few instances, walls and slabs are determined by structural requirements.
 
The roof system is a steel-framed structure with either bracket supports on concrete walls or
 
steel columns supported by the concrete floor at an elevation of 580.0 feet.
In LRA Table 2.4.7.8, the applicant identified the following radwaste building component types that are within the scope of license renewal and subject to an AMR:
* masonry block
* metal roofing
* piles
* reinforced concrete beams, columns, walls, and slabs
* roof membrane
* structural steel beams, columns, plates, and trusses 2.4.7.8.2 Staff Evaluation
 
The staff reviewed LRA Section 2.4.7.8 and UFSAR Section 12.2.5 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
2-208 The staff's review of LRA Section 2.4.7.8 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4-15, dated March 25, 2005, the staff stated that LRA Section 2.4.7.8 states that "The portions of the radwaste building that contain components requiring an AMR include the entire
 
structure and the component supports discussed above." Therefore, the staff requested the
 
applicant to confirm that all structural elements of the radwaste building are scoped and
 
screened in Table 2.4.7.8. If not, the applicant was requested to list those elements of the
 
radwaste building that are excluded from the table and discuss the basis for their exclusion
 
including BFN's assessment of the II/I implication of the excluded elements upon their adjacent
 
in-scope elements pursuant to 10 CFR 54.4 (a)(2).
In its response, by letter dated April 14, 2005, the applicant stated that all structural elements of the radwaste building are scoped and screened in LRA Table 2.4.7.8.
The staff found the above response to RAI 2.4-15 acceptable. Therefore, the staff's concern described in RAI 2.4-15 is resolved.
2.4.7.8.3 Conclusion
 
The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
radwaste building components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the radwaste building components that are subject to an AMR, as required
 
by 10 CFR 54.21(a)(1).
2.4.7.9 Service Building 2.4.7.9.1  Summary of Technical Information in the Application In LRA Section 2.4.7.9, the applicant identified the structures and components of the service building that are subject to an AMR for license renewal.
This structure consists of exterior concrete walls and footings with an interior structural steel frame supported by concrete footings and floor slabs. The building provides office and shop
 
areas for various onsite organizations.
In LRA Table 2.4.7.9, the applicant identified the following service building component types that are within the scope of license renewal and subject to an AMR:
* masonry block
* metal roofing
* reinforced concrete beams, columns, walls, and slabs
* roof membrane 2-209
* structural steel beams, columns, plates, and trusses 2.4.7.9.2  Staff Evaluation
 
The staff reviewed LRA Section 2.4.7.9 and UFSAR Section 12.2.6.2 using the evaluation methodology described in SER Section 2.4. The staff conducted its review in accordance with
 
the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.7.9 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4-16, dated March 25, 2005, the staff stated that LRA Section 2.4.7.9 seems to indicate that only a portion of the service building is scoped and screened in LRA Table 2.4.7.9. Since
 
the LRA provides only a general description of the boundaries between the in-scope and
 
out-of-scope structural elements of the service building, the staff requested the applicant to list
 
those elements of the service building that are excluded from the table and discuss the basis for
 
their exclusion including BFN's assessment of the II/I implication of the excluded elements upon their adjacent in-scope elements pursuant to 10 CFR 54.4 (a)(2).
In its response, by letter dated April 14, 2005, the applicant stated:
During the scoping and screening of the Service Building for the newly identified mechanical systems discussed in the response to RAI 2.1-2A(3), only a limited area of
 
the Service Building contained the new in-scope mechanical piping. Based on that fact, it was determined that the entire structure did not need to be within the scope of license
 
renewal for the period of extended operation and this is described in the second
 
paragraph of the response as noted on page E3-9 and reads as following; "The Service
 
Building contains CO 2 piping and a liquid (water) filled piping for the fire protection system that are required to support fire protection requirements (10 CFR 50.48) based
 
on the criterion of 10 CFR 54.4 (a)(3). Only those rooms of the Service Building that
 
contain the fire protection piping are required to provide structural support and
 
shelter/protection to support the intended function of the fire protection piping."
In order to maintain the structural integrity of the structure within the scope of license renewal and provide reasonable assurance t hat these piping systems will be able to perform their intended functions, a portion of the structure was required to be in-scope
 
such that the structure will perform its intended functions of "shelter/protection" and
 
"structural support" of 10 CFR 54.4(a)(3) components. The in-scope boundary of the
 
Service Building is described in the second paragraph on page E3-10 and reads as
 
following; "In order to maintain the structural integrity of the Service Building to provide 2-210 its intended functions for the in-scope components, the building area considered in-scope for the structure will be extended two column line bays in the west direction to
 
column line S4 and will include the entire structure in the north-south direction between
 
the personnel corridors on elevations 565.0' and 580.0' and roof at elevation 595.0'
 
south of column line Sa to the north exterior wall of the Service Building. It should be
 
noted that column line S7 is the east exterior wall of the Service Building and is located
 
adjacent and parallel to the west exterior wall of the Unit 1 turbine building. Additionally, from the foundation slab at El 565.0' (top of floor slab EL 565.0') to the general roof deck
 
of the structure at EL 595.0' and to EL 605.0' above the mechanical equipment room
 
located between column lines S5 and S6 (west to east) and the Pull-Out Space & Shop
 
Storage between column lines S6 and S7 (west to east) and between column lines Sb to
 
approximately 6 ft north of column line Sh (south to north) defines the in-scope height of
 
the structure." The basis for concluding that the structural integrity boundary of the
 
in-scope structure will be maintained is based on a review of the design of the Service
 
Building.The structural elements of the Service Building that are listed in Table 2.4.7.9 encompass all the structural elements of the Service Building and none were excluded.
The staff found the above response to RAI 2.4-16 acceptable. Therefore, the staff's concern described in RAI 2.4-16 is resolved.
2.4.7.9.3  Conclusion The staff reviewed the LRA, related structural components, and RAI response described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
service building components that are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and the service building components that are subject to an AMR, as required
 
by 10 CFR 54.21(a)(1).
 
====2.4.8 Structures====
and Component Supports Commodities 2.4.8.1  Structures and Component Supports Commodity Group 2.4.8.1.1  Summary of Technical Information in the Application In LRA Section 2.4.8.1, the applicant described the structures and component supports commodity group. This group includes specific types of structures and component support elements located in structures that are within the scope of license renewal. Physical interfaces
 
exist with the structure, system or component being supported and with the building structural
 
element to which the support is anchored. The supports located within a structure that are
 
included within the scope of license renewal are identified under the individual structure's
 
description. The in-scope items include support members, welds, bolted connections, anchorage (including base plate and grout) to the building structure, spring hangers, guides, and building concrete at bolt locations.
2-211 The component supports commodity group includes the following sub-groups: (1) supports for ASME piping and components (GALL Report Items III.B1); (2) supports for cable trays, conduit, HVAC ducts, tube track, instrument tubing and non-ASME piping and components (GALL
 
Report Items III.B2); (3) anchorage of racks, panels, cabinets, and enclosures for electrical
 
equipment and instrumentation (GALL Report Items III.B3); (4) supports for emergency diesel
 
generator (EDG), HVAC system components, and miscellaneous mechanical equipment (GALL Report Items III.B4); and (5) supports for platforms, pipe whip restraints, jet impingement
 
shields, masonry walls, and other miscellaneous structures (GALL Report Items III.B5). The first
 
sub-group includes the supports and support anchorage for ASME-equivalent code class piping
 
and components, or for the components that comprise the interface between the structure and
 
the mechanical component. The second sub-group includes the supports and support
 
anchorage for cable trays, conduits, HVAC ducts, tube track, instrument tubing, and non-ASME
 
piping and components that comprise the interface between the structure and the mechanical, electrical, or instrument component. The third sub-group includes the supports and support
 
anchorage for enclosures of various types that contain and support electrical equipment.
 
Components evaluated in this group comprise the interface between the structure and the
 
electrical or instrument component. The fourth sub-group includes the supports and support
 
anchorage for equipment not addressed in the previous groups that comprise the boundary
 
between the structure and the component. Finally, the fifth sub-group includes structures and
 
anchorage for miscellaneous structures as described above that indirectly support operation.
 
These components comprise the evaluated structure and its anchorage.
A primary function of a support is to provide anchorage for the supported element for DBEs so that the supported element can perform its intended function or functions.
In LRA Table 2.4.8.1, the applicant identified the following structures and component supports commodity group items that are within the scope of license renewal and subject to an AMR:
* ASME-equivalent supports and components
* bolting and fasteners
* cable trays and supports
* conduit and supports
* duct banks and manholes
* electrical panels, racks, cabinets, and other enclosures
* equipment supports and foundations
* HVAC duct supports
* instrument line supports
* instrument racks, frames, panels, and enclosures
* non-ASME equivalent supports and components
* pipe whip restraints and jet impingement shields
* reinforced concrete beams, columns, walls, and slabs
* stairs, platforms, and grating supports
* trenches
* tube rack
* tunnels 2-212 2.4.8.1.2  Staff Evaluation The staff reviewed LRA Section 2.4.8.1, UFSAR Section 5.2 and Appendix C using the evaluation methodology described in SER Section 2.4. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the
 
applicant had not omitted from the scope of license renewal any components with intended
 
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant had identified as being within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components that should be subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.8.1 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.4-13, dated December 20, 2004, the staff stated that the information provided in LRA Section 2.4.8.1 did not make it clear to the staff that all component supports within the scope of
 
license renewal are included in the component supports commodity group. Therefore, the staff
 
requested clarification for several components listed in LRA Table 2.4.8.1. The staff requested
 
the applicant to provide the following:  a.Clarify whether the ASME equivalent supports and components listed in Table 2.4.8.1 include the reactor vessel support skirt/support ring and reactor vessel upper lateral
 
stabilizer support. If not, the applicant was requested (1) to explain where these
 
supports were addressed in the LRA, and (2) to submit the technical basis for crediting an alternate AMP for these supports, if they are not managed by ASME Section XI, Subsection IWF. b.Clarify whether the ASME Equivalent Supports and Components of LRA Table 2.4.8.1 include the drywell lower ring support and the drywell upper lateral support. If the drywell supports are not managed by ASME Section XI, Subsection IWF, the applicant was
 
requested to submit the AMR for them, including the technical basis for this exception. c.Since LRA Section 2.4.8.1 is not referenced anywhere in LRA Sections 2.3 or 2.4, the applicant was requested to verify that all supports associated with components listed in
 
LRA Sections 2.3 and 2.4.1 through 2.4.7 are included in the component types listed in
 
LRA Table 2.4.8.1. If not, the applicant was requested to identify the supports not
 
included and submit the AMR, including credited AMPs. d.Confirm that the "Bolting and Fasteners" listed in LRA Table 2.4.8.1 includes anchors directly installed into concrete.
In its response, by letter dated January 24, 2005, the applicant stated:  a.The reactor vessel support skirt, reactor vessel support ring girder and reactor vessel upper lateral stabilizer are included with "ASME Equivalent Supports and
 
Components" component group as listed in LRA Table 2.4.8.1. See response to 2-213 RAI 2.4-2 (f), RAI 2.4-2 (g) and 2.4-2 (a) for AMR results for these components respectfully. b.The ASME Equivalent Supports and Components of Table 2.4.8.1 do not include the drywell lower ring support and the drywell upper lateral support. Steel
 
Containment Elements in Table 2.4.1.1 include the drywell lower ring support (drywell support skirt) and the drywell upper lateral supports. These components
 
are classified as part of Class MC and BFN is not required to inspect MC supports in accordance with ASME Section XI. Refer to NRC RAIs B.2.1.33-1
 
and B.2.1.33-2 and TVA's responses to those RAIs for justification of why they are not inspected to ASME Section XI, Subsection IWF. The drywell lower ring
 
support is inaccessible (embedded in the Reactor Building concrete). c.LRA Section 2.4.8, "Structures and Component Supports Commodities," includes all supports associated with the components listed in LRA Sections 2.3 and 2.4.1
 
through 2.4.7, with one exception: (1) LRA Table 2.3.1.2 of Section 2.3.1.2 identifies various components internal to the reactor vessel that provide support for other internal
 
components. Aging management of reactor vessel internals components
 
is presented in LRA Table 3.1.2.2. d.In LRA Table 2.4.8.1, the component group "Bolting and Fasteners" was included in error and should be deleted from the table. LRA Table 2.4.8.1 should read as
 
shown below:
LRA Table 2.4.8.1 - Structures and Component Supports
 
Component Type                Intended Functions ASME Equivalent Supports and Components SSCable Trays and Supports SS, and/or SS(NSR)
Conduit and Supports SP, SS, and/or SS(NSR)
Duct Banks, Manholes SS Electrical Panels, Racks, Cabinets, and Other Enclosures SP, SS, and/or SS(NSR)
Equipment Supports and Foundations SS, and/or SS(NSR)
HVAC Duct Supports SS, and/or SS(NSR)
Instrument Line Supports SS, and/or SS(NSR)
Instrument Racks, Frames, Panels & Enclosures SP, SS, and/or SS(NSR)
Non-ASME Equivalent Supports and Components SS, and/or SS(NSR)
Pipe Whip Restraints and Jet Impingement Shields PW and/or HE/ME Reinforced Concrete Beams, Columns, Walls, and Slabs SS, and/or SS(NSR)
Stairs, Platforms, Grating Supports SS, and/or SS(NSR)
Trenches SS(NSR)
Tube Track SS, and/or SS(NSR)
Tunnels SS, and/or SS(NSR)
 
Each of the component support commodity groups identified in LRA section 2.4.8.1
 
includes bolting and anchors, including anchors installed into concrete. This information
 
has been provided in the discussion for the five Structures and Component Supports
 
Commodity Groups in LRA Section 2.4.8, pages 2.4-55 and 2.4-56.
2-214 Item (b) of the above response refers to the applicant's response to RAIs B.2.1.33-1 and B.2.1.33-2, and the applicant's justification for why the drywell lower ring support and the drywell upper lateral support are not inspected to ASME Section XI, Subsection IWF. The staff
 
evaluation covering the applicant's response to RAIs B.2.1.33-1 and B.2.1.33-2 is provided in
 
SER Section 3.0.3.2.21.
The staff found that the applicant response, above, fully addressed the concerns identified in RAI 2.4-13; therefore, the staff's concern described in RAI 2.4-13 is resolved.
In RAI 2.4-14, dated December 20, 2004, the staff stated that based on information provided in LRA Section 2.4, the staff could not identify the insulation and insulation jacketing included
 
within the scope of license renewal nor the specific subsets of insulation and insulation jacketing
 
that are included in LRA Section 2.4 tables. It was also unclear whether insulation and jacketing
 
on the reactor coolant system had been included; therefore, the staff requested the following of
 
the applicant:
* Identify the structures and structural components designated as within the license renewal scope that have insulation and/or insulation jacketing, and identify their location
 
in the plant.
* List all insulation and insulation jacketing materials associated with the item (a) above that require an AMR and the results of the AMR for each.
* For insulation and insulation jacketing materials associated with the item (a) above that do not require aging management, submit the technical basis for this conclusion, including plant-specific operating experience.
* For insulation and insulation jacketing materials associated with the item (a) above that require aging management, identify the AMP(s) credited to manage aging.
In its response, by letter dated January 24, 2005, the applicant stated:
As stated in Section 2.1.7.2 of the Application, Insulation at BFN does not have an intended function within the scope of 10 CFR 54.4(a)(3).
In its response, by letter May 18, 2005, the applicant provided follow-up information to address the staff's concern that insulation was not in scope and subject to an AMR, as stated below:
Thermal insulation is in scope and meets the criteria of 10 CFR 54.4(a)(2) and 10 CFR 54.4(a)(3).
The AMR results for insulation/insulation jacketing are provided in the new Section 3.0.2, shown in Attachment 2 to this response.
The staff found the above response to RAI 2.4-14 acceptable. Therefore, the staff's concern described above is resolved.
2-215 2.4.8.1.3  Conclusion The staff reviewed the LRA, related structural components, and RAI responses described above to determine whether any SSCs that should be within the scope of license renewal had not been
 
identified by the applicant. No omissions were identified. In addition, the staff performed a
 
review to determine whether any components that should be subject to an AMR had not been
 
identified by the applicant. No omissions were identified. On the basis of its review, the staff
 
concluded that there is reasonable assurance that the applicant had adequately identified the
 
structures and component supports commodity group components that are within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and the structures and component supports
 
commodity group components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
====2.4.9 Conclusion====
On the basis of its review, the staff concluded that, pending satisfactory resolution of OI 2.4-3, the applicant had adequately identified the structures and components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the BFN structures and
 
components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
===2.5 Scoping===
and Screening Results: Electrical and Instrumentation and ControlsSystems This section documents the staff's review of the applicant's scoping and screening results for electrical and I&C systems.
In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and list passive, long-lived electrical and I&C SSCs that are within the scope of license renewal and
 
subject to an AMR. To verify that the applicant properly implemented its methodology, the staff focused its review on the implementation results. This approach allowed the staff to confirm that
 
there were no omissions of electrical and I&C system components that meet the scoping criteria and are subject to an AMR.
Staff Evaluation Methodology. The staff's evaluation of the information provided in the LRA was performed in the same manner for all electrical and I&C systems. The objective of the review was to determine if the components and supporting structures for a specific electrical and I&C system that appeared to meet the scoping criteria specified in the Rule had been identified by the applicant as within the scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's screening results to verify that all long-lived, passive components were subject to an AMR in accordance with 10 CFR 54.21(a)(1).
Scoping. To perform its evaluation, the staff reviewed the applicable LRA section and associated component drawings, focusing its review on components that had not been identified as within the scope of license renewal. The staff reviewed relevant licensing basis documents, including the UFSAR, for each electrical and I&C system component to determine if the applicant had omitted components with intended functions delineated under 10 CFR 54.4(a) from the scope of license renewal. The staff also reviewed the licensing basis documents to determine if all intended functions delineated under 10 CFR 54.4(a) had been specified in the LRA. If omissions were identified, the staff requested additional information to resolve the discrepancies.
2-216 Screening. Once the staff completed its review of the scoping results, it evaluated the applicant's screening results. For those systems and components with intended functions, the staff sought to determine (1) if the functions are performed with moving parts or a change in configuration or properties, or (2) if they are subject to replacement based on a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For those that did not meet either of these criteria, the staff sought to confirm that these electrical and I&C systems and components were subject to an AMR as required by 10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested additional information to resolve them.
 
====2.5.1 Electrical====
and Instrumentation and Control Commodities 2.5.1.1  Summary of Technical Information in the Application In LRA Section 2.5.1, the applicant described the electrical and I&C commodities. The electrical and I&C commodities have intended functions to power and control components that meet the
 
requirements of 10 CFR 54.4. For this section, the applicant performed component-level
 
scoping, evaluating by commodities rather than by system components.
The electrical and I&C commodities contain SR components that are relied on to remain functional during, and following, design-basis events. The failure of NSR SSCs in the electrical
 
and I&C commodities could prevent the satisfactory accomplishment of an SR function. In
 
addition, the electrical and I&C commodities perform functions that support fire protection, EQ, ATWS, and SBO.
The intended functions within the scope of license renewal include the following:
* conducts electrical current
* provides electrical insulation
* provides structural support In LRA Table 2.5.1, the applicant identified the following electrical and I&C commodities component types that are within the scope of license renewal and subject to an AMR:
* bus (with enclosures), transmission conductors, and high-voltage insulators (metallic portions)
* bus and high-voltage insulators (non-metallic portions)
* electrical cables and connections not subject to 10 CFR 50.49 EQ requirements (connections include connectors, splices, terminal blocks, fuse blocks/clips, and
 
electrical/I&C penetration assembly pigtails and connectors)
* various electrical equipment subject to 10 CFR 50.49 EQ requirements 2.5.1.2  Staff Evaluation The staff reviewed LRA Section 2.5.1 using the evaluation methodology described in SER Section 2.5. The scoping and screening of electrical and I&C components were performed using
 
the spaces approach described in LRA Section 2.1. The staff conducted its review in 2-217 accordance with the guidance described in SRP-LR Section 2.5, "Scoping and Screening Results - Electrical and Instrumentation and Controls Systems." In the performance of the review, the staff reviewed the UFSAR for any functions delineated under 10 CFR 54.4(a) that had not been identified as intended functions in the LRA, to verify
 
that the SSCs with such functions will be adequately managed to maintain the functions
 
consistent with the CLB for the extended period of operation. The staff then reviewed the LRA to
 
verify that passive or long-lived components were subject to an AMR in accordance with
 
10 CFR 54.21(a)(1).
In LRA Section 2.5.1, the applicant said that the electrical commodities meet the requirements of 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3) and the related requirements
 
for fire protection, EQ, ATWS, and SBO. During its review, the staff identified AMRs for
 
components that are not explicitly addressed for Unit 1. These AMR items are those identified in the scoping and screening evaluation corresponding to LRA Appendices F3, F4, and F7, items
 
shown with a bold-bordered enclosures in LRA Appendix F (see SER Sections 2.6.1.3, 2.6.1.4, and 2.6.1.7). In a letter dated October 8, 2004, the staff requested additional information
 
required for the AMR with respect to these Unit 1 items.
In response to a generic RAI dated January 31, 2005, the applicant provided additional information concerning integration of Unit 1 Restart and License Renewal Activities, which
 
states The license renewal application was structured to reflect the configuration and current
 
licensing basis of all three units. Scoping and screening as well as aging management
 
reviews were done based on the current licensing bases and configuration of all three
 
units. The differences between the units that are relevant to the application and will be
 
resolved prior to Unit 1 restart, are listed in Appendix F. As each activity identified in
 
Appendix F is completed, the corresponding highlighted (bolded bordered) text in the
 
license renewal application will apply to Unit 1. The only change to the application will be
 
to remove the bolded border. No changes are required to scoping and screening results, aging management review results, or TLAAs. In some cases, boundary drawings would
 
change to reflect the bolded bordered text.
The staff reviewed the applicant's response for these items and accepts the methodology as proposed by the applicant for these bold-bordered items throughout the LRA. These
 
modifications are currently not physically impl emented for Unit 1 to match Units 2 and 3 CLB.
However, the applicant stated in its response that the scoping and screening as well as the
 
AMRs are done forward-looking for these bold-bordered enclosure items, based on the CLB for
 
Units 2 and 3, which will also apply to Unit 1 when the modifications are completed. As each
 
activity identified in Appendix F is completed, the corresponding bold-bordered text in the LRA
 
will apply to Unit 1. The applicant commits to update the status of this implementation in a future
 
submittal and through the annual LRA update to the CLB, the next one in January 2006. This
 
commitment will be tracked through a temporary instruction (TI)-2509-01 as a part of the license
 
application verification that this commitment will be completed prior to Unit 1 restart. The
 
applicant also committed to inform the staff as these activities are completed and to reflect the
 
status in annual and other periodic updates. Based on the above, the staff finds this issue for the electrical and I&C resolved.
2-218 In reviewing LRA Section 2.5, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results.
 
Therefore, the staff issued RAIs concerning the specific issues to determine whether the
 
applicant had properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria
 
of 10 CFR 54.21(a)(1). The following discussion describes the staff's RAIs and the applicant's
 
related responses.
In RAI 2.5-1, dated November 1, 2004, the staff stated that in LRA Section 2.5-1, the applicant stated that scoping and screening of electrical and I&C components was performed using the
 
spaces approach described in LRA Section 2.1. Therefore, the staff requested the applicant to
 
specify if all plant spaces had been evaluated using this methodology. If any spaces had been
 
excluded from this evaluation, the staff asked the applicant to identify the excluded spaces and
 
to explain why the spaces were excluded.
In its response, by letter December 1, 2004, the applicant stated:
The "spaces" approach was used for scoping and screening of all plant spaces. The only time the "spaces" approach was not utilized was scoping and screening of the SBO
 
recovery path. The "intended function" approach was utilized to identify which specific
 
components were required for SBO recovery.
The staff found this response acceptable; therefore, the staff's concern described in RAI 2.5-1 is resolved.In RAI 2.5-2, dated November 1, 2004, the staff noted that in LRA Section 2.1.5.2 the applicant had stated that if a component in a commodity group existed in an area where the area
 
conditions exceeded the commodity group's lim iting environmental parameters, a further evaluation could be performed to determine if the component was required for an intended
 
function of a system within the scope of license renewal. Therefore, the staff requested the
 
applicant to identify all the components that were excluded from the scope of license renewal as
 
a result of these further evaluations and to provide the basis used for excluding each
 
component.
By letter of December 1, 2004, the applicant responded as follows:
The following cables or cable types were scoped in by the "spaces" approach but screened out of the scope of license renewal using further evaluations:
Cable Type THHN is PVC [polyvinyl chloride] insulated lighting wire - THHN lighting wire was used in one circuit in the Drywell for normal lighting. This circuit
 
is not required for Appendix R or SBO lighting and was screened out of the
 
scope of license renewal.
Cable Type TW is a PVC insulated ground wire - BFN uses an ungrounded electrical system thus equipment grounds are for personnel protection only and
 
degradation of the PVC insulation would not adversely affect equipment
 
operation.
2-219 The Safe Shutdown Analysis does not list any safety-related intended functions for Source Range Monitors (SRMs) and Intermediate Range Monitors (IRMs)
Nuclear Instrumentation. Therefore, the Source Range and the Intermediate
 
Range Nuclear Instrumentation circuitry are screened out and are not subject to
 
an AMR.The Safe Shutdown Analysis does not list any safety-related functions associated with the Rod Block Monitors (RBMs). Therefore, the RBM circuitry is screened
 
out and is not subject to an AMR.
The only safety-related functions listed in the Safe Shutdown Analysis for the Traversing Incore Probe system (TIP) is provide a reactor coolant pressure boundary. Therefore, TIP circuitry is screened out and is not subject to an AMR.
The following inaccessible medium-voltage cables located in underground conduit duct banks were screened out and not subject to an AMR since they do
 
not perform an intended function for license renewal as specified by
 
10 CFR 54.4.
* Cables routed to Off-gas Treatment Building Transformers A & B
* Cables routed from the Condensate Circulating Water Pumps to the Condensate Circulating Water Pump (CCWP) capacitor banks
* Cables routed to Cooling Tower equipment The staff found the exclusions and the reasons for the exclusions from the scope of license renewal acceptable for all the components except the source range monitor (SRM) and
 
intermediate range monitor (IRM) cables, and the cables routed to off-gas treatment building
 
transformers A and B. In an email dated December 15, 2004, the staff asked the applicant for a
 
further response to RAI 2.5-2, clarifying why these components had been excluded from the
 
scope of license renewal.
The staff contended that nuclear instrumentation circuits cannot be screened out since these circuits perform a safety function and provide tr ip signals to prevent any fuel damage during low power operations. The staff, in support of this item, cited the applicant's statement in LRA
 
Section 2.3.3.32: "The Neutron Monitoring System detects conditions that could lead to local
 
fuel damage and provides signals that can be used to prevent such damage."
With regard to the SRM circuit cables, the staff concurred with the applicant that, because the SRM circuit cables are not designated as SR and they are not in the technical specification for BFN, they do not require an AMR.
With regard to the IRM nuclear instrumentation circuitry, the applicant agreed with the staff that IRM instrumentation circuit cables should be within the scope of license renewal because they are part of the BFN technical specification. Because of this inclusion, the applicant confirmed that their aging effects should be managed by the Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program. All other accessible neutron monitoring subsystem cables and connections will be managed by the Accessible Non-Environment al Qualification Cables and Connections 2-220 Inspection Program. This inclusion impacts the scope of the AMP's elements "Program Description" and "NUREG-1801 Consistency." These changes have been added to the SER Appendix A commitment table, and the applicant will modify the UFSAR supplement to reflect these changes.
With regard to the exclusion of cables routed to off-gas treatment building transformers A and B because they did not serve any intended function, the staff identified technical information in
 
LRA Section 2.3.3.19 that stated that the off-gas system is within the scope of license renewal
 
in accordance with 10 CFR 54.4(a). The SR functions of the off-gas system are to provide flow
 
path integrity for the release of the filtered standby gas treatment system gases to the stack, and to provide automatic closure of back-dra ft prevention dampers to prevent back flow and potential ground-level release of radiation. Therefore, the staff contended that cables routed to
 
off-gas treatment building transformers A & B cannot be screened out.
In its response dated January 18, 2005, the applicant stated that in performing SR functions the off-gas system relies solely on mechanical co mponents that do not require electrical power.
Therefore, the applicant stated that medium-volt age cables routed to off-gas treatment building transformers A and B are screened out and not subject to an AMR.
The staff concurred with the applicant's response dated January 18, 2005, that the intended functions of the off-gas system addressed in LRA Section 2.3.3.19 are accomplished through
 
mechanical means without electrical power. However, the fans of the standby gas treatment
 
system listed in LRA Section 2.3.2.2 are within the scope of license renewal and are powered
 
by these transformers. Therefore, the cables listed in LRA Section 2.3.2.2 as being in the
 
standby gas treatment system should be within the scope of license renewal.
Based on the above, the staff identified additional follow-up to RAI 2.5-2. In an informal request on January 31, 2005, the staff requested clarifications on why these medium-voltage cables to
 
off-gas treatment building transformers A and B had been screened out.
In its response to clarifications to follow up to RAI 2.5-2, by letter dated March 2, 2005, the applicant stated that standby gas treatment blowers, which are within the scope for license
 
renewal, are not powered from off-gas treatment building transformer A and B. The applicant
 
stated that the standby gas treatment system and the off-gas treatment system are completely different systems, independent of each other and located in different buildings that do not share
 
power distribution systems or equipment. Standby gas treatment blowers, which are in scope for license renewal, are not powered from off-gas tr eatment building transformers A and B. In its response dated March 2, 2005, the applicant also provided details of the electrical circuits that
 
support its contention that these blowers ar e not powered from the above transformers. The staff was satisfied with the explanation and considers this issue resolved.
On the basis of its review, the staff found that the applicant had adequately addressed all of the staff's concerns raised in RAI 2.5-2. Therefore, the staff's concerns described in RAI 2.5-2 are resolved.In RAI 2.5-3, dated November 1, 2004, the staff requested additional information regarding the three license renewal drawings identified in LRA Section 2.5.1 that depict the recovery path for
 
SBO and identify the location of each commodity group component in the recovery path circuit.
2-221 In its response, by letter December 1, 2004, the applicant properly identified the location of each commodity group component in the SBO recovery path. The response includes details from the 500 kV switchyard to the 4kV shutdown boards for all three units, transmission conductor runs
 
between breakers, and isolated phase bus runs between the main transformers and the unit
 
station service transformers. The applicant also stated that the SBO recovery path circuits
 
include control circuit wiring. The low-voltage power and control circuit wiring associated with
 
the power circuit breakers and disconnects are included within the scope of license renewal, and there are no 500kV, 161kV, or 4kV underground power circuits used in SBO recovery
 
paths. These details are documented in its response.
The staff found these details were in order and on the basis of its review, the staff found the applicant's response acceptable. Therefore, the staff's concern described in RAI 2.5-3 is
 
resolved.In RAI 2.5-4, dated November 1, 2004, the staff stated that during a teleconference held on July 28, 2004, in response to a request for additional information, RAI 3.6-3, the applicant stated that in 1997 a cross-linked polyethylene (XLPE)-insulated CCWP capacitor bank cable failed
 
in-service at BFN. Therefore, the staff requested that the applicant explain why these cables
 
were not included within the scope of license renewal and identified as a component that
 
requires an AMR.
In its response to RAI 2.5-4, the applicant stated that the condensate circulating water (CCW) system (system 027) is within the scope of lic ense renewal because it provides manual vacuum breaking capability to prevent backflow from the cooling tower warm channel into the forebay
 
upon trip of the CCW pumps. The capacitor bank provides additional starting power for the
 
condenser circulating water pumps to minimize l oading on the electrical distribution system. But, as previously stated in the response to RAI 2.5-2, above, the CCWP capacitor bank cables are
 
medium-voltage cables that do not perform an intended function for license renewal as specified
 
in 10 CFR 54.4. The staff had previously accepted the applicant's position that these cables are
 
screened out and not subject to an AMR.
On the basis of its review, the staff found that the applicant had adequately addressed the staff's concern. Therefore, the staff's concern described in RAI 2.5-4 is resolved.
2.5.1.3  Conclusion During its review of the information provided in the LRA, RAI responses, and the UFSAR, the staff did not identify any omissions or discrepancies in the applicant's scoping and screening
 
results for electrical and I&C commodities. In addition, the staff performed a review to determine
 
whether any components that should be subject to an AMR had not been identified by the
 
applicant. No omissions were identified. On the basis of its review, the staff concluded that the
 
applicant had adequately identified the electrical and I&C commodities components that are
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and the electrical and I&C
 
commodities components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-2222.6  Integration of Browns Ferry Nuclear, Unit 1, Restart Activities and License Renewal Activities BFN was designed and constructed by the applicant and licensed in 1973, 1974, and 1976 respectively. The three units are identical GE BWR/4 reactors with Mark I containments. The units operated from original licensing until 1985 w hen they were voluntarily shut down by the applicant to address management and technical issues. The applicant then implemented a
 
comprehensive nuclear performance plan to correct the deficiencies that led to the shutdown.
 
This plan included changes in management, programs, processes, and procedures, as well as
 
extensive equipment refurbishment, replacem ent, and modifications. Unit 2 was subsequently restarted in 1991, and Unit 3 followed in 1995. In the early 1990s, the applicant decided to defer
 
restart of Unit 1. On May 16, 2002, the applicant announced the Unit 1 restart project. The
 
applicant had previously notified the staff of its intent to submit an LRA for Units 2 and 3 by
 
December 31, 2003. The applicant met with the staff on July 24, 2002, to discuss its proposal to
 
submit the LRA for all three units. Subsequent meetings were held with the staff on October 31, 2002, April 23, 2003, and September 29, 2003. Meeting summaries are documented by letters
 
dated November 25, 2002, June 2, 2003, and October 30, 2003, respectively, regarding the
 
license renewal application. In those meetings, agreement was reached with the staff on the
 
content and format of the application to ensure that it met all regulatory requirements and
 
supported staff review.
License Renewal Application Content. In the meetings referenced above, the applicant explained that, although it was engaging in numerous plant modifications and restart activities, the CLB for Unit 1 was well-known, defined, and documented, and the LRA would be prepared
 
based on the CLB. The unique element with Unit 1 is that restart activities include modifying the
 
Unit 1 licensing basis to make it consistent with the CLB of Units 2 and 3. During the meetings
 
with the staff, it was agreed the applicant would identify in the LRA the Unit 1 differences that
 
will be eliminated when restart activities are completed. To highlight these differences, information not yet applicable to Unit 1 was marked with a bolded border. This annotation
 
methodology is consistent with previous multi-plant LRAs submitted to the staff. LRA
 
Appendix F describes each of these differences, its effect on the application, and the schedule
 
for resolution. It also provides references to application sections affected. This enabled the
 
applicant to submit an LRA based on the CLB for all three units, as well as to identify Unit 1
 
restart activities relevant to the LRA. As previously stated, the BFN units are essentially
 
identical, and the application is not unit-specific with regard to AMPs. The changes being
 
implemented as part of Unit 1 restart activities are consistent with the changes made previously
 
to Units 2 and 3. The AMPs are common for all three units because at restart the Unit 1
 
licensing basis will be the same as the licensing basis for Units 2 and 3.2.6.1  Regulatory Framework for Review of BFN LRA and Integration Unit 1 Restart Activities By letter dated December 31, 2003, the applicant submitted an application pursuant to 10 CFR 54 to renew the operating licenses for the BFN Units 1, 2, and 3. The applicant is
 
submitting additional information concerning the status of Unit 1 restart activities and the impact
 
of those activities on the LRA. LRA Appendix F states that the Unit 1 restart program will result
 
in three operationally identical BFN units, providing assurance that the Unit 1 CLB changes
 
implemented prior to restart will result in the same CLB as that of Units 2 and 3 and that, 2-223 therefore, the AMPs for each unit are the same. The Unit 1 CLB differences described in LRA Appendix F will be resolved prior to Unit 1 restart.
BFN has a single UFSAR common to all three units. Unit 1 has been maintained in essentially the same physical configuration as it was when it was shut down in 1985 (except for systems
 
required to keep Unit 1 in the shutdown condition or to support Units 2 and 3 operation). As
 
required by 10 CFR 50.71, the UFSAR was updated for all three units when amendments were
 
issued common to all the units. In 1998, the Unit 1 Technical Specifications were converted to
 
Improved Technical Specifications, as they were for Units 2 and 3. The license renewal UFSAR
 
supplement Appendix A identifies and describes the AMPs that are required for all three units.
 
No AMPs unique to Unit 1 are required during the period of extended operation. However, for
 
portions of Unit 1 systems that have not been replaced, the staff concluded that there was
 
insufficient operating history or data to conclude that one-time inspections are appropriate
 
substitutes for periodic inspections. Based on the advice from the interim review by the ACRS in
 
its 526th subcommittee meeting and in resolving the staff concerns in this matter, AMP
 
B.2.1.42, "Unit 1 Periodic Inspection Program," was added to supplement one-time inspections.
 
The committee also felt that periodic inspections are the most significant compensating actions
 
for the lack of plant-specific operating experience of BFN Unit 1. This new AMP is only
 
applicable to Unit 1 and was added as a result of the staff reaching an agreement with the
 
applicant for managing piping and components left in place, specifically, the ones subjected to
 
the layup program.
The LRA was structured to reflect the configuration and CLB of all three units. Scoping and screening as well as AMRs were done based on the configuration and CLB of all three units.
 
The differences between the units that are relevant to the application, and which will be
 
resolved prior to Unit 1 restart, are listed in LRA Appendix F.
As each activity identified in LRA Appendix F is completed, the corresponding highlighted (bold-bordered) text in the LRA will apply to Unit 1. The only change to the application will be to
 
remove the bolded border. No changes are required to scoping and screening results, AMR
 
results, or TLAAs. In some cases, boundary drawings would change to reflect the
 
bold-bordered text. Accordingly, the staff reviewed all the bold-bordered items in the LRA as
 
they will exist when Unit 1 restarts. The staff review of Unit 1 items focused on the material, aging effect, and AMPs as they exist in Units 2 and 3. There was no unique impact of these
 
evaluations on Unit 1 items, because the applicant stated that there were no unique AMPs for
 
Unit 1. The BFN procedures for AMPs apply site-wide and BFN procedures for new AMPs and
 
AMP enhancements will be issued for all three units.
LRA Appendix F provides the applicant's plans and the schedules for Unit 1 restart activities affecting the LRA. Whenever text shown with a bold-bordered box appears in the LRA, indicating a licensing or design basis that only applies to Units 2 and 3, a link is provided to the
 
appropriate LRA Appendix F section.
LRA Appendix F summarizes the resolution of the differences between Unit 1 and Units 2 and 3.
For each difference, the following information is presented:
Description
- Describes the difference.
2-224 Difference Resolution
- Explains the methodologies and activities that the applicant plans to use to disposition each licensing or design-basis difference.
LRA Impact
- Summarizes changes that would be expected to the LRA, if the condition were resolved prior to issuance of the renewed licenses.
Schedule for Completion
- Relates to milestones rather than specific dates. The schedules reflect the current schedules in the Unit 1 restart plan and are subject to change as the plan is
 
implemented. The following milestones have been defined:
* Prior to renewed license issuance - The applicant expects the resolution activities to be complete prior to the expected issuance date of the renewed licenses.
* Prior to restart - The applicant will complete the resolution activities prior to Unit 1 restart.
* Permanent - The difference is acceptable as-is for license renewal. No changes related to license renewal are necessary or planned for the condition.
* If a submittal is required, the submittal milestone is stated.
* Systems/structures/components impact ed - The impacted systems, structures, or components are identified with links to the appropriate sections in LRA Chapter 2
 
sections and the appropriate LRA Chapter 3 sections.
* AMPs/TLAAs Impacted - The impacted AMPs and TLAAs are identified with links to the appropriate section in LRA Chapter 4 and Appendix B.
Staff Evaluation Methodology.
In reviewing the technical information provided in LRA Appendix F, and January 31, 2005, letter, the staff review was limited to verifying (1) the sufficiency of information provided by the app licant for the 13 items that impacted the LRA review, (2) the applicability of the 13 items to Un it 1, (3) the systems these 13 items impacted, and (4) the plan to resolve differences between the CLB for Unit 1 and the CLB for Units 2 and 3, so that upon restart all units will have the same CLB. It should be noted that in the LRA the restart activities listed in LRA Appendix F are generally referred to as differences in the design
 
basis or licensing basis. Based on the definition of CLB in 10 CFR 54.3, these activities are
 
more precisely described as implementation ac tivities of the design and licensing basis. Even though each of the 13 activities listed in LRA Appendix F is committed to and planned for
 
completion prior to Unit 1 restart, any unimplemented commitments would remain valid, part of
 
the CLB, carry over into the renewed license period, and be controlled by the NRC regulatory
 
and oversight process.
The staff's evaluation of the information provi ded in the LRA was performed in the same manner for all mechanical, civil, electrical systems as it relates to the particular item in question. The
 
objective of the review was to determine if the components and supporting structures for a
 
specific mechanical system that appeared to meet the scoping criteria specified in the Rule had
 
been identified by the applicant as being within the scope of license renewal. Similarly, the staff
 
evaluated the applicant's screening results to verify that all long-lived, passive components are
 
subject to an AMR in accordance with 10 CFR 54.21(a)(1).
Specific planned Unit 1 restart activities that impact license renewal are provided below.
2-2252.6.1.1  Main Steam Isolation Valve Alternate Leakage Treatment Description. In LRA Section F.1 the applicant described the proposed modification. The Unit 1 CLB for MSIV leakage does not incorporate an alternate leakage treatment pathway utilizing
 
main steam system piping and main condenser. The Unit 1 main steam piping from the
 
outermost isolation valve up to the turbine stop valve, the bypass/drain piping to the main
 
condenser, and the main condenser is being evaluated and will be modified as required to
 
ensure structural integrity is retained during and following an SSE. This will allow use of
 
methodology that assumes plateout and holdup in the piping and condenser (in LOCA offsite
 
and control room dose calculations) for radioactive leakage past the MSIVs. In the LRA, the
 
applicant stated that this methodology was included in the Units 2 and 3 CLB and will be
 
incorporated prior to Unit 1 restart.
Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and 3 will be resolved prior to Unit 1 restart by approval of a technical specification change dated
 
July 9, 2004, and implementation of the actions committed to in the proposed change prior to
 
Unit 1 restart. The applicant committed to revise plant operating procedures to provide
 
procedural requirements to establish the alternate leakage treatment path to the condenser and
 
to resolve the outliers identified in the supporting analysis.
LRA Impact. The Unit 1 systems and structures impac ted by this modification and their LRA sections and tables:
* high pressure coolant injection (Section 2.3.2.3)
* auxiliary boiler (Section 2.3.3.1)
* sampling and water quality (Section 2.3.3.14)
* reactor core isolation cooling (Section 2.3.3.23)
* main steam (Section 2.3.4.1 and Table 3.4.2.1)
* condensate and demineralized water (Section 2.3.4.2 and Table 3.4.2.2)
* heater drains and vents (Sections 2.3.4.4 and 3.4.2.1.4 and Table 3.4.2.4)
* turbine drains and miscellaneous piping (Sections 2.3.4.5 and 3.4.2.1.5 and Table 3.4.2.5)
* turbine buildings (Section 2.4.7.1)
Following resolution of this item, the license renewal results shown with a bold-bordered box in the sections identified above will be applicable to Unit 1.
Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart and currently forecasted to be completed by August 2006. Should the applicant not receive
 
approval of technical specification (TS)-436, the effect on the license renewal is that the Unit 1
 
components credited in the MSIV alternate leakage pathway will not be within the scope of
 
license renewal as currently planned. The Unit 1 boundary drawings will remain accurate and
 
the increased scope identified by the bold-bordered boxes in the application will not be
 
applicable. Staff reviews of the application would not change.
Staff Evaluation. The applicant evaluated the impacts to the scoping and screening of the affected SSCs because of this Unit 1 restart modification. The applicant stated that after
 
approval of the proposed change (TS-436) and implementation of the actions committed to in
 
the proposed change prior to Unit 1 restart, there will be no functional differences in the 2-226 alternate leakage treatment pathways between Units 1, 2, and 3. The Unit 1 components that comprise the alternate leakage treatment pathway will be incorporated into the appropriate
 
AMPs specified in the LRA, and there will be no unit-specific differences. The staff also
 
concurred with the applicant's evaluation that there are no changes to the previously evaluated
 
intended function of respective system s and components screened and scoped previously.
In addition, Unit 1 modifications impact LRA Section 2.1 "Scoping and Screening Methodology,"
which relates to the leakage pathway MSIV's structural integrity. In its response dated May 31, 2005, the applicant provided information related to RAI 2.1-2A(1) and (2) concerning NSR
 
components that affect SR piping regarding the secondary containment integrity and also
 
related to RAIs 2.3.4.4-1 and 2.3.4.4-2. The staff found the applicant's response to
 
RAI 2.1-2A(1) and (2) acceptable; therefore, RAIs 2.3.4.4-1 and 2.3.4.4-2 are closed.
In its submittal dated January 31, 2005, the applicant forecasted that this modification will be completed by August 2006. This commitment will be tracked through a temporary instruction
 
TI-2509-01 as a part of the license application verification that this commitment be will
 
completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter
 
the period of extended operation without implementing this modification.
Conclusion. During its review of the information provided in the LRA, license renewal drawings, RAI responses, and licensing-basis information, the staff did not identify any omissions or
 
discrepancies in the applicant's scoping and screening results for the structures and
 
components because of the MSIV alternate leakage treatment modification. The scoping and
 
screening reviews were done based on the CLB. The differences between the units' CLBs that
 
are relevant to the application will be resolved prior to Unit 1 restart. The Unit 1 systems and
 
structures impacted by this modification, and their LRA sections and tables as indicated in the
 
list above, were evaluated in SER Section 2.1.3.1.2, and the staff requested additional information. RAIs 2.1-2A(1) and (2) are related to seismic qualification of secondary
 
containment penetration seals. The MSIV alternate treatment modification potential involves one
 
such penetration. The staff in reviewing the structures and components impacted by these
 
modifications concluded that the applicant had adequately identified Unit 1 SSCs within the
 
scope of license renewal, as required by 10 CFR 54.4 (a), and the SSCs that are subject to an
 
AMR, as required by 10 CFR 54.21 (a)(1).
2.6.1.2  Containment Atmosphere Dilution System Description. The CAD system consists of six pneumatic valves per unit, each with its own accumulator and check valve. The CAD system wa s originally designated for short-term use after DBEs. Long-term use (up to 100 days) was not considered in the original design. A request
 
to consider the long-term use of the CAD system was included in NUREG 0737 (TMI action
 
Plan), Item II.K.3.28 (Qualification of CAD Accumulators). The safety evaluation that documents
 
the acceptability of the applicant's plan to satisfy Item II.K.3.28 for all three units was provided
 
previously by letter dated July 24, 1985.
The CAD system must have the capability to supply pressurized nitrogen to operate the main steam relief valves when control air is not available to ensure the safe shutdown requirements
 
of 10 CFR  Part 50, Appendix R following fires, and 10 CFR 50.63 during an SBO. That
 
capability has been installed on Units 2 and 3 and will be installed on Unit 1.
2-227 Difference Resolution. The differences between Unit 1 versus Units 2 and 3 will be resolved prior to Unit 1 restart by upgrading the Unit 1 CAD accumulator system and implementing its
 
CLB, letter to NRC dated July 12, 1984. The capability to supply pressurized nitrogen to operate
 
the main steam relief valves for the long-term when control air is not available will be provided by splitting the ring header into two sections and providing an alternate nitrogen supply to the
 
drywell control air system.
LRA Impact. The Unit 1 systems and structures impac ted by this modification and their LRA sections:
* containment (2.3.2.1)
* containment atmosphere dilution (2.3.2.7)
* control air (2.3.3.10)
* sampling and water quality (2.3.3.14)
* reactor building closed cooling water (2.3.3.22)
* radioactive waste treatment (2.3.3.25)
* feedwater (2.3.4.3)
Following resolution of this item, the license renewal results shown with a bold-bordered box in the sections identified above will be applicable to Unit 1.
Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart and currently forecasted to be completed by July 2006. Should the applicant not make the
 
modifications discussed above, the associated additional components planned to be installed
 
would not be installed and, therefore, the additional components would not be within the scope
 
of license renewal as currently planned. The Unit 1 boundary drawings would remain accurate
 
and the increased scope identified by the bold-bordered boxes in the application would not be
 
applicable. Staff reviews of the application would not change.
Staff Evaluation. Once the Unit 1 modifications are completed there will be no functional differences in the containment atmosphere dilution nitrogen supply between Units 1, 2, and 3.
 
The Unit 1 components that comprise the containment atmosphere dilution nitrogen supply will
 
be incorporated into the appropriate AMPs specified in the LRA, and there will be no
 
unit-specific differences. As stated above, this modification is forecasted to be completed by
 
July 2006, and it will be duly tracked by a separate LRA Appendix A commitment and LRA
 
inspection prior to Unit 1 restart to confirm implementation.
In its submittal dated January 31, 2005, the applicant forecasted that this modification will be completed by August 2006. This commitment will be tracked through a temporary instruction
 
TI-2509-01 as a part of the license application verification that this commitment will be
 
completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter
 
the period of extended operation without implementing this modification.
Conclusion. During its review of the information provided in the LRA, license renewal drawings, and licensing-basis information, the staff did not identify any omissions or discrepancies in the
 
applicant's scoping and screening results for the structures and components because of the
 
containment atmosphere dilution system modification. The scoping and screening reviews were
 
done based on the CLB. The differences between the units' CLBs that are relevant to the
 
application will be resolved prior to Unit 1 rest art. The Unit 1 systems and structures impacted 2-228 by this modification, and their LRA sections and tables as indicated in the list above, were evaluated elsewhere in the SER, and the staff did not identify any omissions or discrepancies.
 
Therefore, the staff concluded that the applicant had adequately identified the Unit 1 SSCs
 
within the scope of license renewal, as required by 10 CFR 54.4 (a), and the SSCs that are
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.6.1.3  Fire Protection Description. The applicant is required by 10 CFR  Part 50, Appendix R to have the capability to maintain safe shutdown during and after a fire at BFN station. The staff issued an SER, dated
 
December 8, 1988, for the 10 CFR  Part 50, Appendix R-Fire Protection Program, "Browns
 
Ferry Nuclear Plant, Units 1, 2, and 3 - Appendix R Safe Shutdown System Analysis," and
 
supplemental safety evaluation, dated November 3, 1989, on the subject. In addition, by letter
 
dated March 6, 1991, the staff issued an associated license amendment. The SER for the fire
 
protection plan and fire hazards analysis was provided by staff letter to TVA, "Fire Protection
 
Program - Browns Ferry Nuclear Plant Units 1, 2, and 3," dated March 31, 1993. The applicant's
 
Fire Protection Report, Volume 1 (UFSAR Chapter 10.11), states that the 10 CFR  Part 50, Appendix R requirements for operating units have been established and implemented for
 
Units 2 and 3. The staff has also issued a license amendment for the 10 CFR  Part 50, Appendix R post-fire safe shutdown program, dated November 2, 1995.
Difference Resolution. The differences between the current fire protection licensing basis for Unit 1 and the CLB for Units 2 and 3 will be resolved prior to Unit 1 restart by implementation of
 
the Fire Protection Program on Unit 1.
LRA Impact. The Unit 1 systems, structures, and AMPs impacted by this modification and their LRA sections:
* reactor recirculation (2.3.1.4)
* containment (2.3.2.1)
* high pressure coolant injection (2.3.2.3)
* residual heat removal (2.3.2.4)
* containment atmosphere dilution (2.3.2.7)
* residual heat removal service water (2.3.3.3)
* high pressure fire protection (2.3.3.6)
* control air (2.3.3.10)
* sampling and water quality (2.3.3.14)
* emergency equipment cooling water (2.3.3.20)
* reactor water cleanup (2.3.3.21)
* reactor building closed cooling water (2.3.3.22)
* reactor core isolation cooling (2.3.3.23)
* radioactive waste treatment (2.3.3.25)
* fuel pool cooling and cleanup (2.3.3.26)
* control rod drive (2.3.3.29)
* main steam (2.3.4.1)
* condensate and demineralized water (2.3.4.2)
* feedwater (2.3.4.3)
* primary containment structure (2.4.1.1)
* reactor buildings (2.4.2.1) 2-229
* turbine buildings (2.4.7.1)
* electrical and instrumentation and control commodities (2.5.1)
* Fire Protection Program (B.2.1.23)
* Fire Water System Program (B.2.1.24)
Following resolution of this item, the license renewal results shown with a bold-bordered box in the sections identified above will be applicable to Unit 1.
It is reasonable to assume that the Fire Protection Program will be implemented prior to Unit 1 restart.Schedule for Completion. The Unit 1 analyses and modifications are scheduled for completion prior to restart and currently forecasted to be completed by August 2006.
Staff Evaluation. Once the Unit 1 Fire Protection Program modifications are completed there will be no functional differences between Units 1, 2, and 3. The Unit 1 components that comprise
 
the high pressure fire protection system will be incorporated into the appropriate AMPs specified
 
in the LRA and there will be no unit-specific differences. The staff review of Unit 1 items focused
 
on the material, aging effects, and AMPs as they exist in Units 2 and 3, and there were no
 
impacts of the evaluations on Unit 1 items, because the applicant stated that there was no
 
unique AMP for Unit 1. The staff found the explanation acceptable.
In its submittal dated January 31, 2005, the applicant forcasted that this modification will be completed by August 2006. This commitment will be tracked through a temporary instruction
 
TI-2509-01 as a part of the license application verification that this commitment will be
 
completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter
 
the period of extended operation without implementing this modification.
Conclusion. During its review of the information provided in the LRA, license renewal drawings, and licensing-basis information, the staff did not identify any omissions or discrepancies in the
 
applicant's scoping and screening results for the structures and components because of the fire
 
protection modification. The scoping and screening reviews were done based on the CLB. The
 
differences between the units' CLBs that are relevant to the application will be resolved prior to
 
Unit 1 restart. The Unit 1 systems and structures impacted by this modification, and their LRA sections and tables as indicated in the list above, were evaluated elsewhere in the SER, and
 
the staff did not identify any omissions or discrepancies. Therefore, the staff concluded that the
 
applicant had adequately identified the Unit 1 SSCs within the scope of license renewal, as
 
required by 10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.6.1.4  Environmental Qualification Description. A site-wide EQ Program required by 10 CFR 50.49 has been developed for BFN, and implemented on Units 2 and 3, and it is expected to be implemented on Unit 1 to ensure
 
compliance with 10 CFR 50.49.
As part of the recovery program for Browns Ferry, by October 24, 1988 letter, the applicant committed to implement its EQ Program so that electrical equipment located in a harsh
 
environment would meet 10 CFR 50.49 requirements prior to the restart of each unit. The safety 2-230 evaluation for the program was issued by the staff on January 23, 1991. The site-wide EQ Program required by 10 CFR 50.49 was developed for BFN, implemented on Units 2 and 3, and
 
is being implemented on Unit 1. This program defines responsibilities and specifies
 
requirements to establish and maintain auditable documentation demonstrating the
 
environmental qualification of equipment. This pr ogram is described in LRA Section 4.4.
The EQ Program:
* Identifies the applicable DBAs and determines the environmental parameters for those accidents. The environmental parameters are necessary for procurement, design, and qualification of equipment in accordance with 10 CFR 50.49.
* Identifies the equipment and cables in the harsh zones within the scope of 10 CFR 50.49 and determines their required operating times.
* Is established or procured and documented for each piece of equipment in the 10 CFR 50.49 list. Environmental Qualification Data Packages provide documented
 
evidence that demonstrates the qualification of each piece of equipment for its specific
 
application and environment. Components subject to 10 CFR 50.49 requirements that
 
are not qualified for the license term must be refurbished, replaced, or have their
 
qualification extended prior to reaching the aging limits established in their evaluation.
* Actions are identified, proceduralized, and initiated to maintain the qualification of installed equipment and cables. This includes periodic, preventive, or corrective
 
maintenance; procurement controls; and storage requirements. The safety evaluation for
 
the program was issued by the staff on January 23, 1991.
Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and 3 will be resolved prior to Unit 1 restart by im plementation of the EQ Program on Unit 1, as stated in the LRA Sections 4.4 and B.3.1.
UFSAR Impact.
The Unit 1 systems, structures, commodities, AMPs, and TLAAs impacted by this modification and its LRA sections and tables:
* reactor recirculation (Section 2.3.1.4)
* containment (Section 2.3.2.1)
* high pressure coolant injection (Section 2.3.2.3)
* residual heat removal (Section 2.3.2.4)
* core spray (Section 2.3.2.5)
* containment inerting (Section 2.3.2.6)
* containment atmosphere dilution (Section 2.3.2.7)
* control air (Section 2.3.3.10)
* sampling and water quality (Section 2.3.3.14)
* emergency equipment cooling water (Section 2.3.3.20)
* reactor water cleanup (Section 2.3.3.21)
* reactor building closed cooling water (Section 2.3.3.22)
* reactor core isolation cooling (Section 2.3.3.23)
* radioactive waste treatment (Section 2.3.3.25)
* control rod drive (Section 2.3.3.29) 2-231
* radiation monitoring (Section 2.3.3.31)
* main steam (Section 2.3.4.1)
* feedwater (Section 2.3.4.3)
* primary containment structure (Section 2.4.1.1)
* reactor buildings (Section 2.4.2.1)
* electrical and I&C commodities (Section 2.5.1 and Tables 3.6.1 and 3.6.2.1)
* EQ TLAA (Section 4.4)
* EQ Program (Section B.3.1)
Following resolution of this item, the license renewal results shown with a bold-bordered box in the sections identified above will be applicable to Unit 1.
Schedule for Completion. The Unit 1 analyses and modification is scheduled for completion prior to restart and currently forcasted to be completed by July 2006.
Staff Evaluation. The differences between the CLB for Unit 1 and the CLB for Units 2 and 3 will be resolved prior to Unit 1 restart by implementat ion of the EQ Program. Once the Unit 1 portion of the EQ Program is completed, the BFN site-wide EQ Program will ensure that the
 
components subject to 10 CFR 50.49 requirements are maintained within the bounds of their
 
qualification bases for the period of extended operation.
In its submittal dated January 31, 2005, the applicant forcasted that this modification will be completed by August 2006. This commitment will be tracked through a temporary instruction
 
TI-2509-01 as a part of the license application verification that this commitment will be
 
completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter
 
the period of extended operation without implementing this modification.
Conclusion. During its review of the information provided in the LRA, license renewal drawings, and licensing-basis information, the staff did not identify any omissions or discrepancies in the
 
applicant's scoping and screening results for the structures and components because of the EQ
 
modification. The scoping and screening reviews were done based on the CLB. The differences
 
between the units' CLBs that are relevant to the application will be resolved prior to Unit 1
 
restart. The Unit 1 systems and structures impact ed by this modification, and their LRA sections and tables as indicated in the list above, were evaluated elsewhere in the SER, and the staff did
 
not identify any omissions or discrepancies. Therefore, the staff concluded that the applicant
 
had adequately identified the Unit 1 SSCs within the scope of license renewal, as required by
 
10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.6.1.5  Intergranular Stress Corrosion Cracking The applicant submitted and implemented plans for addressing intergranular stainless steel stress corrosion cracking in accordance with generic letter (GL) 88-01 and Supplement 1 for
 
Units 2 and 3. In accordance with the Unit 1 restart plan, GL 88-01 will be addressed for Unit 1.
Description. The BWR Stress Corrosion Cracking Program manages IGSCC in reactor coolant pressure boundary components made of stainless steel.
The applicant's program to address GL 88-01, the staff position on IGSCC in BWR austenitic stainless steel piping, for Unit 3 was provided by letter dated December 28, 1992. The 2-232 applicant, by its letter dated August 1, 1988, previously committed to submit a report containing the details of the repair or replacement work. The safety evaluation documenting the
 
acceptability of the program was provided and supplemental information regarding Unit 1 was
 
submitted by letter dated December 3, 1993. The following wrought austenitic stainless steel
 
piping systems and components on Unit 1 are considered susceptible to IGSCC according to
 
the guidelines given in GL 88-01:
* reactor recirculation from the recirculation inlet and outlet nozzles to the connections with RHR
* RHR from the recirculation system to the first isolation valve outside of the drywell penetration
* reactor water cleanup (RWCU) from its connection to the RHR system to first isolation valve outside of the drywell penetration
* core spray from the core spray inlet nozzles to the drywell penetration, including the core spray inlet safe ends
* jet pump instrument safe ends In its letter, dated July 21, 2004, the applicant informed the staff that the IGSCC-susceptible piping on Unit 1 is being replaced using materials that are resistant to IGSCC. To address the
 
requirements for inspection schedules and expansion plans, the susceptible weldments have
 
been categorized according to NUREG 0313, Revision 2, Section 5, Table 1. The in-service
 
inspections are required by BFN Technical Requirements Manual, Section 3.4.3.
Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and 3 will be resolved Unit 1 prior to restart by t he replacement of the IGSCC-susceptible piping, and by providing IGSCC protection or mitigation.
UFSAR Impact. The Unit 1 systems and AMPs impacted by this modification and their LRA sections and table:
* reactor vessel (Section 2.3.1.1)
* reactor recirculation (Section 2.3.1.4)
* residual heat removal (Section 2.3.2.4)
* core spray (Section 2.3.2.5 and Table 3.2.2.5)
* reactor water cleanup (Section 2.3.3.21)
* Boiling Water Reactor Stress Corrosion Cracking Program (B.2.1.10)
* BWR Reactor Water Cleanup System Program (B.2.1.22)
It is reasonable to assume that replacement of the IGSCC-susceptible piping will be performed.
The applicant has already removed the original piping and must replace it to operate the unit.
 
Following resolution of this item, the license renewal results shown with a bold-bordered box in
 
the sections identified above will be applicable to Unit 1.
Schedule for Completion. Submittal of the Unit 1 IGSCC plan and implementation report, as well as the physical modification, are scheduled for completion prior to restart and currently
 
forcasted to be completed by March 2006. This commitment will be tracked through a temporary
 
instruction TI-2509-01 as a part of the license application verification that this commitment will 2-233 be completed prior to Unit 1 restart. Other license conditions will not allow the applicant to enter the period of extended operation without implementing this modification.
Staff Evaluation. Once the piping replacement modifications are completed on Unit 1 there will be no functional differences in the IGSCC mitigation or protection between Units 1, 2, and 3.
 
The Unit 1 components that mitigate IGSCC will be incorporated into the appropriate AMPs and
 
there will be no unit-specific differences.
In its submittal dated January 31, 2005, the applicant forcasted that this modification will be completed by August 2006. Other license conditions will not permit the applicant to enter the
 
period of extended operation without implementing this modification.
Conclusion. During its review of the information provided in the LRA, license renewal drawings, and licensing-basis information, the staff did not identify any omissions or discrepancies in the
 
applicant's scoping and screening results for the structures and components because of the
 
IGSCC modification. The scoping and screening reviews were done based on the CLB. The
 
differences between the units' CLBs that are relevant to the application will be resolved prior to
 
Unit 1 restart. The Unit 1 systems and structures impacted by this modification, and their LRA sections and tables as indicated in the list above, were evaluated elsewhere in the SER, and
 
the staff has not identified any omissions or discrepancies. Therefore, the staff concluded that
 
the applicant had adequately identified the Unit 1 SSCs within the scope of license renewal, as
 
required by 10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.6.1.6  Boiling Water Reactor Vessel and Internals Project Inspection and Flaw Evaluation Guidelines Implementation Summary of Technical Information. During Unit 1's extended outage, the BWRVIP was initiated to develop inspection and flaw evaluation guidelines. The following guidelines will be
 
implemented on Unit 1 during its restart.
BWRVIP-03 Reactor Pressure Vessel and Internals Examination Guidelines BWRVIP-05 BWR Reactor Pressure Vessel Shell Weld Inspection Recommendations
 
BWRVIP-06-A Safety Assessment of BWR Reactor Internals
 
BWRVIP-15 Configurations of Safety-Related BWR Reactor Internals
 
BWRVIP-18 BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines
 
BWRVIP-25 BWR Core Plate Inspection and Flaw Evaluation Guidelines
 
BWRVIP-26 BWR Top Guide Inspection and Flaw Evaluation Guidelines
 
BWRVIP-27-A BWR Standby Liquid Control System
/Core Plate Inspection and Flaw Evaluation Guidelines BWRVIP-38 BWR Shroud Support Inspection and Flaw Evaluation Guidelines
 
BWRVIP-41 BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines
 
BWRVIP-47 BWR Lower Plenum Inspection and Flaw Evaluation Guidelines
 
BWRVIP-48 Vessel ID Attachment Weld Inspection and Flaw Evaluation
 
BWRVIP-49-A Instrument Penetration Inspection and Flaw Evaluation Guidelines
 
BWRVIP-74-A BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines
 
BWRVIP-75 Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules
 
BWRVIP-76 BWR Core Shroud Inspection and Flaw Evaluation Guidelines
 
BWRVIP-94 Program Implementation Guide 2-234 BWRVIP-104 Evaluation and Recommendations to Address Shroud Support Cracking in BWRs Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and 3 with regard to the reactor vessel and internal inspection criteria will be resolved prior to Unit 1
 
restart by the implementation of the BWRVIP guidelines on Unit 1.
UFSAR Impact. The Unit 1 systems and AMPs impacted by this modification and their LRA sections:
* reactor vessel (3.1.2.2.16)
* reactor vessel internals (3.1.2.2.16)
* Boiling Water Reactor Vessel Inside Diameter Attachment Welds Program (B.2.1.7)
* Boiling Water Reactor Penetrations Program (B.2.1.11)
* Boiling Water Reactor Vessel Internals Program (B.2.1.12)
It is reasonable to assume that the applicant will implement the BWRVIP guidelines. Without
 
continued commitment to the BWRVIP, the applicant would have to independently develop and
 
obtain staff approval of alternate methodologies for Unit 1, which is not economically feasible.
Following resolution of this item, the license renewal results shown with a bold-bordered box in the sections identified above will be applicable to Unit 1.
Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart and currently forcasted to be completed by November 2005.
Staff Evaluation. Prior to restart of Unit 1, the BWRVIP information included in the application will be implemented on Unit 1.
In its submittal dated January 31, 2005, the applicant forcasted that this modification will be completed by November 2006. This commitment will be tracked through a temporary instruction
 
TI-2509-01 as a part of the license application verification that this commitment will be
 
completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter
 
the period of extended operation without implementing this modification.
Conclusion. During its review of the information provided in the LRA, license renewal drawings, and licensing-basis information, the staff did not identify any omissions or discrepancies in the
 
applicant's scoping and screening results for the structures and components because of the
 
BWRVIP and flaw evaluation guidelines implementation modification. The scoping and
 
screening reviews were done based on the CLB. The differences between the units' CLBs that
 
are relevant to the application will be resolved prior to Unit 1 restart. The Unit 1 systems and
 
structures impacted by this modification, and their LRA sections and tables as indicated in the
 
list above, were evaluated elsewhere in the SER, and the staff has not identified any omissions
 
or discrepancies. Therefore, the staff concluded that the applicant had adequately identified the
 
Unit 1 SSCs within the scope of license renewal, as required by 10 CFR 54.4 (a), and the SSCs
 
that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.6.1.7  Anticipated Transients Without Scram 2-235 Description. Section 50.62 of 10 CFR requires applicants to reduce the risk from ATWS events.
The applicant adopted the BWR Owners' Group recommendation for implementation of the
 
ATWS rule by letter dated March 1, 1988. The staff approval of the applicant's approach for
 
satisfying 10 CFR 50.62 was provided on January 22, 1989, and the associated TS changes
 
were approved on January 26, 1989. TS 3.3.4.2 for the BFN units provides the requirements for
 
the ATWS recirculation pump trip (ATWS-RPT) instrumentation. TS 3.1.7, SLC system, for the
 
BFN units provides requirements for ATWS that satisfy 10 CFR 50.62. In its letter dated
 
November 29, 1990, the applicant confirmed its commitment to install the required ATWS
 
modifications prior to Unit 1 restart. Design features described in UFSAR Chapter 7.19 will be
 
installed on Unit 1.
Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and 3 will be resolved prior to Unit 1 restart by impl ementation of the ATWS modifications on Unit 1.
The CRD system will have a diverse scram (i.e. alte rnate rod injection) in accordance with LRA Section 2.3.3.29.
UFSAR Impact. The Unit 1 systems, structures, and comm odities impacted by this modification and their LRA sections:
* reactor core isolation cooling (2.3.3.23)
* control rod drive (2.3.3.29)
* feedwater (2.3.4.3)
* primary containment structure (2.4.1.1)
* reactor buildings (2.4.2.1)
* electrical and instrumentation and control commodities (2.5.1)
Following resolution of this item, it is expected that the license renewal results shown with a bold-bordered box in the sections identified above will be applicable to Unit 1.
Schedule for Completion. The Unit 1 analyses and modifications are scheduled for completion prior to restart. If for any reason, the applicant changes its planned actions to address
 
10 CFR 50.62, it will need to submit a revised TS change for staff approval and address the
 
aging management aspects of the changes as necessary.
Staff Evaluation. After the implementation of the ATWS modifications on Unit 1 there will be no functional differences in the ATWS system between Units 1, 2, and 3. The Unit 1 components
 
that perform the ATWS function will be incorporated into the appropriate AMPs specified in the
 
LRA and there will be no unit-specific differences.
In its submittal dated January 31, 2005, the applicant forcasted that this modification will be completed by May 2006. This commitment will be tracked through a temporary instruction
 
TI-2509-01 as a part of the license application verification that this commitment will be
 
completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter
 
the period of extended operation without implementing this modification.
Conclusion. During its review of the information provided in the LRA, license renewal drawings, and licensing-basis information, the staff did not identify any omissions or discrepancies in the
 
applicant's scoping and screening results for the structures and components because of the
 
ATWS modification. The scoping and screening reviews were done based on the CLB. The 2-236 differences between the units' CLBs that are relevant to the application will be resolved prior to Unit 1 restart. The Unit 1 systems and structures impacted by this modification, and their LRA sections and tables as indicated in the list above, were evaluated elsewhere in the SER, and
 
the staff did not identify any omissions or discrepancies. Therefore, the staff concluded that the
 
applicant had adequately identified the Unit 1 SSCs within the scope of license renewal, as
 
required by 10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.6.1.8  Reactor Vessel Head Spray Description. The reactor vessel head spray piping is susceptible to IGSCC and was included in GL 88-01. The applicant responded to GL 88-01 for all three units by letter dated August 1, 1988. In that letter, the applicant notified the staff that it had previously removed the head spray
 
piping from Units 2 and 3, and planned to remove the head spray piping from Unit 1 prior to
 
startup. The staff's approval was provided on De cember 3, 1993. The applicant reconfirmed, in its July 21, 2004, supplemental response to GL 88-01 for Unit 1, that it planned to remove the
 
reactor vessel head spray piping prior to Unit 1 restart.
On Units 2 and 3, the reactor vessel head spray piping within the drywell has been removed and the reactor vessel head penetration has a flanged cap installed. The primary containment
 
isolation valves have been removed and the primary containment penetration has been sealed.
 
Head spray piping has also been removed and a permanent welded cap has been installed at
 
the RHR system interface with its head spray header.
Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and 3 will be resolved prior to Unit 1 restart by performing these head spray modifications on Unit 1.
 
Once the head spray modifications are completed on Unit 1 prior to restart, the physical and
 
operational differences between Unit 1 and Units 2 and 3 will be resolved UFSAR Impact. The Unit 1 systems impacted by this modification and their LRA sections:
Reactor Vessel Internals (2.3.1.2)
Residual Heat Removal (2.3.2.4)
Following resolution of this item, the license renewal results shown with a bold-bordered box in the LRA sections identified above will be applicable to Unit 1.
Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart and currently forcasted to be completed by June 2006.
Staff Evaluation. After the implementation of the reactor vessel head spray modifications on Unit 1 there will be no functional differences in the reactor vessel head spray system between
 
Units 1, 2, and 3. The Unit 1 components that perform the reactor vessel head spray function
 
will be incorporated into the appropriate AMPs specified in the LRA, and there will be no
 
unit-specific differences.
In its submittal dated January 31, 2005, the applicant forcasted that this modification will be completed by June 2006. This commitment will be tracked through a temporary instruction
 
TI-2509-01 as a part of the license application verification that this commitment will be 2-237 completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter the period of extended operation without implementing this modification.
Conclusion. During its review of the information provided in the LRA, license renewal drawings, and licensing-basis information, the staff did not identify any omissions or discrepancies in the
 
applicant's scoping and screening results for the structures and components because of the
 
reactor vessel head spray modification. The scoping and screening reviews were done based
 
on the CLB. The differences between the units' CLBs that are relevant to the application will be
 
resolved prior to Unit 1 restart. The Unit 1 syst ems and structures impacted by this modification, and their LRA sections and tables as indicated in the list above, were evaluated elsewhere in
 
the SER, and the staff did not identify any omissions or discrepancies. Therefore, the staff
 
concluded that the applicant had adequately identified the Unit 1 SSCs within the scope of
 
license renewal, as required by 10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.6.1.9  Hardened Wetwell Vent Description. In GL 89-16, dated September 1, 1989, the staff requested applicants with Mark I containments to voluntarily install a hardened wetwell vent. In response, the applicant
 
committed, by letter dated October 30, 1989, to install a hardened wetwell vent prior to restart of
 
each unit. The hardened wetwell vent has been installed on Units 2 and 3, but has not yet been
 
implemented on Unit 1.
Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and 3 will be resolved prior to Unit 1 restart by the installation of the hardened wetwell vent on
 
Unit 1. Once the modifications are completed, the physical and operational differences between
 
Unit 1 and Units 2 and 3 will be resolved.
UFSAR Impact. The Unit 1 system and structure impact ed by this modification and their LRA sections:
* containment (2.3.2.1)
* reinforced concrete chimney (2.4.6.1)
Following resolution of this item, the license renewal results shown with a bold-bordered box in the sections identified above are applicable to Unit 1.
Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart and this modification is currently forcasted to be completed by May 2006. If for any reason, the
 
applicant decided it would implement an alternate solution to GL 89-19, the applicant would be
 
required to notify the staff, and include any alternate modifications within the appropriate AMPs.
Staff Evaluation. After the Unit 1 hardened wetwell vent modifications are completed, there will be no functional differences in the associated systems for Units 1, 2, and 3. The Unit 1
 
components that comprise the hardened wetwell vent will be incorporated into the appropriate
 
AMPs specified in the LRA, and there will be no unit-specific differences.
In its submittal dated January 31, 2005, the applicant forcasted that this modification will be completed by May 2006. This commitment will be tracked through a temporary instruction 2-238 TI-2509-01 as a part of the license application verification that this commitment will be completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter
 
the period of extended operation without implementing this modification.
Conclusion. During its review of the information provided in the LRA, license renewal drawings, and licensing-basis information, the staff did not identify any omissions or discrepancies in the
 
applicant's scoping and screening results for the structures and components because of the
 
hardened wetwell vent modification. The scoping and screening reviews were done based on
 
the CLB. The differences between the units' CLBs that are relevant to the application will be
 
resolved prior to Unit 1 restart. The Unit 1 syst ems and structures impacted by this modification, and their LRA sections and tables as indicated in the list above, were evaluated elsewhere in
 
the SER, and the staff did not identify any omissions or discrepancies. Therefore, the staff
 
concluded that the applicant had adequately identified the Unit 1 SSCs within the scope of
 
license renewal, as required by 10 CFR 54.4 (a), and the SSCs subject to an AMR, as required
 
by 10 CFR 54.21(a)(1).
2.6.1.10  Service Air and Demineralized Water Primary Containment Penetrations Description. The staff requested, by letter dated May 5, 1992, information regarding Unit 1 compliance with NUREG-0737, Item II.E.4.2; and 10 CFR  Part 50, Appendix J. The staff
 
compared the Unit 1 containment isolation scheme to the Unit 2 design and concluded, in the
 
January 6, 1995, safety evaluation, that the isolation design was acceptable. Currently, the configuration of the Unit 1 primary containment penetrations numbers, X-20 and X-21, are
 
different from the corresponding configuration on Units 2 and 3. On Unit 1 the penetrations are
 
piped to the service air and demineralized water systems with primary containment isolation valves. On Units 2 and 3, they are capped and not assigned to a service system. These
 
penetrations on Unit 1 will be capped and made identical to those of Units 2 and 3.
Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and 3 will be resolved prior to Unit 1 restart by making the Unit 1 configuration the same as the
 
current Units 2 and 3 configuration. Once the service air and demineralized
 
water systems modifications are completed on Unit 1, the physical and operational differences
 
between Unit 1 versus Units 2 and 3 will be resolved.
If for any reason, the applicant decided it would not implement the committed modifications, the applicant would be required to notify the staff so that the following action to bring the item into
 
the scope of managed piping would apply. The Unit 1 associated piping and components that
 
are to be removed are shown on the Unit 1 boundary drawings and if the piping were not
 
removed, the AMPs specified in the LRA would apply. Thus, there would be no change in the
 
application if the committed modifications were not completed.
UFSAR Impact. The Unit 1 systems impacted by this modification and their LRA sections:
* service air (2.3.3.11)
* condensate and demineralized water (2.3.4.2)
Following resolution of this item, the license renewal results shown with a bold-bordered box in the LRA sections identified above will be applicable to Unit 1.
2-239 Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart and is currently forecasted to be completed by May 2006.
Staff Evaluation. After the modifications to the Unit 1 service air and condensate and demineralized systems piping are completed there will be no functional differences in the
 
associated primary containment configurations for Units 1, 2, and 3.
In its submittal dated January 31, 2005, the applicant forcasted that this modification will be completed by May 2006. This commitment will be tracked through a temporary instruction
 
TI-2509-01 as a part of the license application verification that this commitment will be
 
completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter
 
the period of extended operation without implementing this modification.
Conclusion. During its review of the information provided in the LRA, license renewal drawings, and licensing-basis information, the staff did not identify any omissions or discrepancies in the
 
applicant's scoping and screening results for the structures and components because of the
 
service air and demineralized water primary containment penetrations modification. The scoping
 
and screening reviews were done based on the CLB. The differences between the units' CLBs
 
that are relevant to the application will be resolved prior to Unit 1 restart. The Unit 1 systems
 
and structures impacted by this modification, and their LRA sections and tables as indicated in
 
the list above, were evaluated elsewhere in the SER, and the staff did not identify any omissions
 
or discrepancies. Therefore, the staff concluded that the applicant had adequately identified the
 
Unit 1 SSCs within the scope of license renewal, as required by 10 CFR 54.4 (a), and the SSCs
 
that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.6.1.11  Auxiliary Decay Heat Removal System Description. As described in UFSAR 10.22, the ADHR system only serves Units 2 and 3. The only intended function for license renewal is to provide secondary containment integrity for the
 
ADHR system's piping that transfers the fuel pool heat.
The ADHR system provides an NSR means to re move decay heat and residual heat from the spent fuel pool and reactor cavity, and currently serves only Units 2 and 3. The ADHR allows
 
servicing of the RHR system components earlier in an outage, thus, potentially reducing the outage duration. The only intended function for license renewal is to provide secondary
 
containment integrity for the ADHR system's piping that transfers the fuel pool heat to the heat sink outside containment. There is currently only a single piping loop serving both Units 2 and 3
 
that penetrates the secondary containment.
The configuration of the ADHR system will be modified to service Unit 1 as well as Units 2 and
: 3. When modified, there will continue to be only a single piping loop that penetrates the
 
secondary containment. That loop and its secondary containment penetrations will serve all
 
three units.
Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and 3 will be resolved prior to Unit 1 restart by modi fying the ADHR system to service Unit 1 as well as Units 2 and 3. When modified, there will continue to be only a single piping loop that
 
penetrates the secondary containment. That loop and its secondary containment penetrations 2-240 will serve all three units. Once the ADHR modifications are completed on Unit 1 prior to restart, the physical and operational differences between Unit 1 and Units 2 and 3 will be resolved.
UFSAR Impact. The Unit 1 system impacted by this m odification and its LRA sections and table is the auxiliary decay heat removal system (2.3.3.24 and 3.3.2.1.24 and Table 3.3.2.24).
Following resolution of this item, the license renewal results shown with a bold-bordered box in the LRA sections and table identified above will be applicable to Unit 1. Should the applicant not
 
make the modifications discussed above, the applicant would be required to notify the staff.
 
Since these associated additional components planned to be installed would not be installed, the boundary drawings for Unit 1 would not change, and the additional components would not
 
be included within the appropriate AMPs as currently planned.
Schedule for Completion. The Unit 1 modification is scheduled for completion prior to Unit 1 restart and is currently projected to be complete by May 2005.
Staff Evaluation. After the modifications to the ADHR system are completed there will be no functional differences in the system for Units 1, 2, and 3.
In its submittal dated January 31, 2005, the applicant forcasted that this modification will be completed by May 2006. This commitment will be tracked through a temporary instruction
 
TI-2509-01 as a part of the license application verification that this commitment will be
 
completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter
 
the period of extended operation without implementing this modification.
Conclusion. During its review of the information provided in the LRA, license renewal drawings, and licensing-basis information, the staff did not identify any omissions or discrepancies in the
 
applicant's scoping and screening results for the structures and components because of the
 
ADHR system modification. The scoping and screening reviews were done based on the CLB.
 
The differences between the units' CLBs that are relevant to the application will be resolved
 
prior to Unit 1 restart. The Unit 1 systems and stru ctures impacted by this modification, and their LRA sections and tables as indicated in the list above, were evaluated elsewhere in the SER, and the staff did not identify any omissions or discrepancies. Therefore, the staff concluded that
 
the applicant had adequately identified the Unit 1 SSCs within the scope of license renewal, as
 
required by 10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as required by
 
10 CFR 54.21(a)(1). 2.6.1.12  Maintenance Rule Description. By letter dated August 9, 1999, the staff issued a partial temporary exemption.
This exempts the applicant from the specific scoping requirements of 10 CFR 50.65(b) and
 
allows it to maintain the defueled and long-term layup status of Unit 1. The exemption does not
 
impact Maintenance Rule scoping for equipment required to be functional to support Unit 1 in its
 
defueled status or equipment required to support operation of Units 2 and 3.
The scoping results for the affected SSCs will not be changed. No changes are expected for AMR results or TLAAs.
The temporary exemption expires upon restart of Unit 1.
2-241 Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and 3 will be resolved upon the restart of Unit 1, when the temporary exemption ceases to be
 
effective. Specifically, with respect to the CLB differences identified in the application, the
 
differences in the Maintenance Rule implementation will be resolved.
UFSAR impact. There are no Unit 1 systems impacted by this modification because Unit 1 SSCs not required to be functional during the current shutdown and defueled status are not
 
included within the scope of the Maintenance Rule.
Schedule for Completion. The committed completion date is at Unit 1 restart because the temporary exemption will expire upon Unit 1 restart and the full scope of the Maintenance Rule
 
will apply to Unit 1.
Staff Evaluation , After the Maintenance Rule modifications are completed upon Unit 1 restart, there will be no functional differences in the system for Units 1, 2, and 3.
As stated above, this modification is forcasted to be completed upon Unit 1 restart, and it will be duly tracked by a separate LRA Appendix A commitment and LRA inspection prior to restart to
 
confirm implementation.
In its submittal dated January 31, 2005, the applicant forcasted that this modification will be completed by Unit 1 restart. This commitment will be tracked through a temporary instruction
 
TI-2509-01 as a part of the license application verification that this commitment will be
 
completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter
 
the period of extended operation without implementing this modification.
Conclusion. During its review of the information provided in the LRA, license renewal drawings, and licensing-basis information, the staff did not identify any omissions or discrepancies in the
 
applicant's scoping and screening results for the structures and components because of the
 
Maintenance Rule modification. The scoping and screening reviews were done based on the
 
CLB. The differences between the units' CLBs that are relevant to the application will be
 
resolved prior to Unit 1 restart. The Unit 1 syst ems and structures impacted by this modification, and their LRA sections and tables as indicated in the list above, were evaluated elsewhere in
 
the SER, and the staff did not identify any omissions or discrepancies. Therefore, the staff
 
concluded that the applicant had adequately identified the Unit 1 SSCs within the scope of
 
license renewal, as required by 10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.6.1.13  Reactor Water Cleanup System Description. BFN has selected an option in the RWCU System Program that allows the applicant not to test system piping outboard of the outboard primary containment isolation valve
 
provided that the following actions are completed:
* The RWCU piping outside the outboard primary containment isolation valves will be replaced with IGSCC-resistant piping
* The actions requested in GL 89-10 SR Motor-Operated Valve Testing and Surveillance, will be satisfactorily completed for the RWCU system; and, in addition, the RWCU 2-242 system will be reconfigured so that the pumps are no longer exposed to a high temperature environment, consistent with Units 2 and 3.
The applicant committed to replace the 4-inch and larger, stainless steel, RWCU piping located outside the drywell prior to the restart of Unit 1. The applicant also committed to develop and
 
implement a comprehensive Motor-operated Valve Testing and Surveillance Program for Unit 1, satisfying the intent of GL 89-10. At the time of its restart, the Unit 1 RWCU system will have
 
been reconfigured so that the pumps are no l onger exposed to a high-temperature environment.
Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and 3 will be resolved prior to Unit 1 restart by performing the actions described above. Once these
 
actions have been implemented, there will be no operational differences between the Unit 1
 
RWCU system and the Units 2 and 3 systems.
UFSAR Impact. The Unit 1 system and AMP impacted by this modification and their LRA sections:
* reactor water cleanup (2.3.3.21)
* Reactor Water Cleanup System Program (B.2.1.22)
Following resolution of this item, the license renewal results shown with a bold-bordered box in the LRA sections identified above will be applicable to Unit 1.
Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart and is currently projected to be complete by July 2006.
The applicant will have completed the above commitments prior to Unit 1 restart since the piping has been removed and the system is being reconfigured as described above. Other license
 
conditions will not allow the applicant to enter the period of extended operation without
 
implementing this modification Staff Evaluation. Prior to the restart of Unit 1, the applicant will have completed replacement of the RWCU system piping outside the outboard primary containment isolation valves, and
 
completed implementation of its GL 89-10 program, such that the Unit 1 differences identified in
 
the application in this regard are no longer applicable.
In its submittal dated January 31, 2005, the applicant forcasted that this modification will be completed by July 2006. This commitment will be tracked through a temporary instruction
 
TI-2509-01 as a part of the license application verification that this commitment will be
 
completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter
 
the period of extended operation without implementing this modification.
Conclusion. During its review of the information provided in the LRA, license renewal drawings, and licensing-basis information, the staff did not identify any omissions or discrepancies in the
 
applicant's scoping and screening results for the structures and components because of the
 
reactor water cleanup system modification. The scoping and screening reviews were done
 
based on the CLB. The differences between the units' CLBs that are relevant to the application
 
will be resolved prior to Unit 1 restart. The Un it 1 systems and structures impacted by this modification, and their LRA sections and tables as indicated in the list above, were evaluated 2-243 elsewhere in the SER, and the staff did not identify any omissions or discrepancies. Therefore, the staff concluded that the applicant had adequately identified the Unit 1 SSCs within the
 
scope of license renewal, as required by 10 CFR 54.4 (a), and the SSCs that are subject to an
 
AMR, as required by 10 CFR 54.21(a)(1).
 
====2.6.2 Staff====
Evaluation The staff evaluation of LRA Appendix F items used the methodology described in SER Section 2.6.1 to determine whether these items had been adequately scoped and screened.
 
The staff did not perform any safety review of any of these modifications, but performed a limited disposition of the resolution activities for each of the LRA Appendix F items that will be
 
completed prior to Unit 1 restart. As stipulated and agreed upon with the staff in its
 
pre-application meetings, the applicant provided in its submittal dated January 31, 2005, "Additional Information Concerning the Integration of Unit 1 Restart and License Renewal
 
Activities," a status update on completion of the restart activities that impact the CLB of Unit 1.
 
The SER with OI presents the latest information on these modifications. Accordingly, the staff
 
found that the disposition and validation of the modifications were consistent with the
 
commitments. The staff will track modifications and implementation details of these items via separate LRA inspections prior to Unit 1 restart to confirm implementation.
In reviewing the technical information provided in LRA Appendix F, the staff review was limited to verifying: (i) The sufficiency of information provided by the applicant for the 13 items that impacted the LRA review. (ii) The applicability of the 13 items to Unit 1.
(iii)The systems these 13 items impact.
(iv)The plan to resolve differences between the CLB for Unit 1 and the CLB for Units 2 and 3, so that upon restart all units will have the same CLB.
It should be noted that in the LRA the restart activities listed in LRA Appendix F were generally referred to as differences in the design basis or licensing basis. Based on the definition of CLB
 
in 10 CFR 54.3, these activities are more precis ely described as implementation activities of the design and licensing basis. Even though each of the 13 activities listed in LRA Appendix F is
 
committed to and planned for completion prior to Unit 1 restart, any unimplemented
 
commitments would remain valid, part of the CLB, carry over into the renewed license period, and be controlled by the NRC regulatory and oversight process.
The staff's evaluation of the information provi ded in the LRA was performed in the same manner for all mechanical, civil, and electrical systems as it relates to the particular item in question.
 
The objective of the review was to determine if the components and supporting structures for a
 
specific mechanical system that appeared to meet the scoping criteria specified in the Rule
 
were identified by the applicant as being within the scope of license renewal. Similarly, the staff
 
evaluated the applicant's screening results to verify that all long-lived, passive components were
 
subject to an AMR in accordance with 10 CFR 54.21(a)(1).
2-2442.6.3Conclusion The restart plan ensures compliance with the applicant's commitments made during the shutdown and with regulatory requirements that changed during the extended shutdown. In
 
addition, a license condition will be imposed as part of LRA review that will require the Unit 1
 
restart activities, described in LRA Appendix F, to be completed prior to Unit 1 restart.
 
Therefore, while implementation of the 13 items identified in LRA Appendix F is not yet
 
complete, the staff found that this will not be a barrier to staff approval of license renewal for
 
Unit 1. This type of approval has not been made for commitments in prior LRAs approved by the staff. Therefore, there are no staff evaluations or staff findings performed for these 13 LRA
 
Appendix F items, except for restating the technical information provided in the LRA and the
 
January 31, 2005, letter, in the format described below and a status update on the physical
 
implementation of these Unit 1 restart activities.
During its review of the information provided in LRA Appendix F, the staff did not identify any omissions or discrepancies in the applicant's integration of Unit 1 restart activities with license
 
renewal activities. Therefore, the staff concluded that, pending satisfactory implementation of
 
the activities identified in LRA Appendix F prior to Unit 1 restart, the applicant had adequately
 
identified the Unit 1 systems, structures, and components that will be within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and the Unit 1 structures and components that will be
 
subject to an AMR, as required by 10 CFR 54.21(a)(1). Satisfactory completion of these actions
 
prior to Unit 1 restart will be a condition of the renewed license.
2-245 2.7  Conclusion for Scoping and Screening The staff reviewed the information in LRA Section 2, "Scoping and Screening Methodology for Identifying Structures and Components Subject to Aging Management Review and
 
Implementation and Results." The staff determined that the applicant's scoping and screening
 
methodology, including its supplement 10 CFR 54.4(a)(2) review which brought additional NSR
 
piping segments and associated components into the scope of license renewal, was consistent
 
with the requirements of 10 CFR 54.21(a)(1) and the staff's position on the treatment of SR and
 
NSR SSCs within the scope of license renewal and the structures and components requiring an
 
AMR is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1).
On the basis of its review, the staff concluded, pending resolution of OI 2.4-3, that the applicant had adequately identified those systems and components that are within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and t hose systems and components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
With regard to these matters, the staff concluded that there is reasonable assurance that the activities authorized by the renewed license can continue to be conducted in accordance with
 
the CLB, and any changes made to the BFN CLB, in order to comply with 10 CFR 54.29(a), are
 
in accord with the Act and the Commission's regulations.
2-246 THIS PAGE IS INTENTIONALLY LEFT BLANK 3-1  SECTION 3 AGING MANAGEMENT REVIEW RESULTS This section of the safety evaluation report (SER) contains the staff's evaluation of the applicant's AMPs (AMPs) and aging management reviews (AMRs). In License Renewal Application (LRA) Appendix B, the applicant described the 39 AMPs that it relies on to manage
 
or monitor the aging of long-lived, passive components and structures.
In LRA Section 3, the applicant provided the results of the AMRs for those structures and components that were identified in LRA Section 2 as being within the scope of license renewal
 
and subject to an AMR.
 
===3.0 Applicant's===
Use of the Generic Aging Lessons Learned Report In preparing its LRA, Tennessee Valley Authority (TVA, the applicant) credited U.S. Nuclear Regulatory Commission Regulatory Guide (NUREG)-1801, "Generic Aging Lessons Learned
 
[GALL] Report," dated July 2001. The GALL Report contains the Nuclear Regulatory
 
Commission's (NRC or the staff's) generic evaluation of the existing plant programs, and it
 
documents the technical basis for determining where existing programs are adequate without
 
modification and where existing programs s hould be augmented for the period of extended operation. The evaluation results documented in the GALL Report indicate that many of the
 
existing programs are adequate to manage the aging effects for particular structures or
 
components for license renewal without change. The GALL Report also contains
 
recommendations on specific areas for which existing programs should be augmented for
 
license renewal. An applicant may reference the GALL Report in a license renewal application
 
to demonstrate that the programs at its facility correspond to those reviewed and approved in
 
the GALL Report.
The purpose of the GALL Report is to provide the staff with a summary of staff-approved AMPs to manage or monitor the aging of structures and components that are subject to an AMR. If an
 
applicant commits to implementing these staff-approved AMPs, the time, effort, and resources
 
used to review an applicant's LRA will be greatly reduced, thereby improving the efficiency and effectiveness of the license renewal review process. The GALL Report also serves as a
 
reference for applicants and staff reviewers to quickly identify those AMPs and activities that the
 
staff determined will adequately manage or monitor aging during the period of extended
 
operation.
The GALL Report identifies (1) systems, structures, and components (SSCs), (2) structure and component (SC) materials, (3) the environments to which the SCs are exposed, (4) the aging
 
effects associated with the materials and environments, (5) the AMPs that are credited with
 
managing or monitoring the aging effects, and (6) recommendations for further applicant
 
evaluations of aging management for certain component types.
To determine whether using the GALL Report would improve the efficiency of the license renewal review, the staff conducted a demonstration project to exercise the GALL process and
 
to determine the format and content of a safety evaluation based on this process. The results of
 
the demonstration project confirmed that t he GALL process will improve the efficiency and 3-2 effectiveness of the LRA review, while maintaining the staff's focus on public health and safety.
NUREG-1800, "Standard Review Plan for the Review of License Renewal Applications,"
(SRP-LR), dated April 2001, was prepared based on both the GALL Report model and lessons
 
learned from the demonstration project.
The staff performed its review in accordance with the requirements of Title 10, Part 54, of the Code of Federal Regulations (10 CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants," and the guidance provided in the SRP-LR and the GALL
 
Report.The staff performed onsite audits at the applicant's offices in Chattanooga, TN, during the weeks of June 25 and July 19, 2004, and additional technical reviews of the applicant's AMPs
 
and AMRs. The objective of the audits and reviews was to verify that the effects of aging on
 
structures and components will be adequately managed so that their intended functions will be
 
maintained consistent with the plant's current licensing basis (CLB) for the period of extended
 
operation, as required by 10 CFR 54, "Requirements for Renewal of Operating Licenses for
 
Nuclear Power Plants." Detailed results of the staff's onsite audits are documented in "Audit
 
Report for Plant AMPs and Aging Management Reviews - Browns Ferry Nuclear Plant Units 1, 2, and 3," dated April 26, 2005.3.0.1  Format of the License Renewal Application TVA submitted an application that followed the standard LRA format, as agreed to between the NRC staff and the Nuclear Energy Institute (NEI) (see letter dated April 7, 2003, ML030990052).
 
This revised LRA format incorporates lessons learned from the staff's reviews of the previous
 
five LRAs. These previous LRAs used a form at developed from information gained during an NRC staff and NEI demonstration project that was conducted to evaluate the use of the GALL
 
Report in the staff's review process.
The organization of LRA Section 3 parallels Chapter 3 of the SRP-LR. The AMR results information in LRA Section 3 is presented in the following two table types:
* Table 1: Table 3.x.1 - where "3" indicates the LRA section number, "x" indicates the subsection number from the GALL Report, and "1" indicates that this is the first table
 
type in LRA Section 3.
* Table 2: Table 3.x.2-y - where "3" indicates the LRA section number, "x" indicates the subsection number from the GALL Report, "2" indicates that this is the second table type
 
in LRA Section 3, and "y" indicates the system table number.
The content of the previous applications and the Browns Ferry Nuclear Plant (BFN) application is essentially the same. The intent of the revised format used for the BFN application was to
 
modify the tables in Chapter 3 to provide additional information that would assist the staff in its review. In Table 1, TVA summarized the portions of the application that it considered to be
 
consistent with the GALL Report. In Table 2, TVA identified the linkage between the scoping
 
and screening results in Chapter 2 and the AMRs in Chapter 3.
3-3 3.0.1.1  Overview of Table 1 Table 3.x.1 (Table 1) provides a summary comparison of how the facility aligns with the corresponding tables of the GALL Report, Volume 1. The table is essentially the same as
 
Tables 1 through 6 provided in the GALL Report, Volume 1, except that the "Type" column has
 
been replaced by an "Item Number" column and the "Item Number in GALL" column has been
 
replaced by a "Discussion" column. The "Item Number" column provides the reviewer with a
 
means to cross-reference from Table 2 to Table 1. The "Discussion" column is used by the
 
applicant to provide clarifying and amplifying information. The following are examples of information that might be contained within this column:
* further evaluation recommended - information or reference to where that information is located
* the name of a plant-specific program being used
* exceptions to the GALL Report assumptions
* a discussion of how the line is consistent with the corresponding line item in the GALL Report when this may not be intuitively obvious
* a discussion of how the item is different than the corresponding line item in the GALL Report (e.g., when there is exception taken to an AMP that is listed in the GALL Report)
The format of Table 1 allows the staff to align a specific Table 1 row with the corresponding GALL Report, Volume 1, table row so that the consistency can be easily checked.
3.0.1.2  Overview of Table 2 Table 3.x.2-y (Table 2) provides the detailed results of the AMRs for those components identified in LRA Section 2 as being subject to an AMR. The LRA contains a Table 2 for each of
 
the components or systems within a system gr ouping (e.g., reactor coolant systems, engineered safety features, auxiliary systems, etc.). For example, the engineered safety features group contains tables specific to the containment spray system, containment isolation system, and emergency core cooling system, Table 2 consists of the following nine columns:  1.Component Type - The first column identifies all of the component types from Section 2 of the LRA that are subject to AMR. They are listed in alphabetical order. 2.Intended Function - The second column contains the license renewal intended functions (using abbreviations where necessary) for the listed component types. Definitions and
 
abbreviations of passive component type intended functions are presented in
 
Table 2.0.1, Intended Function Abbreviations and Definitions. 3.Material - The third column lists the particular materials of construction for the component type. 4.Environment - The fourth column lists the environment to which the component types are exposed. Internal and external service env ironments are indicated, as appropriate.
Descriptions of the internal and external service environments that were used in the
 
AMR to determine aging effects requiring management are included in Table 3.0.1, Internal Service Environments, and Table 3.0.2, External Service Environments.
3-4  5.Aging Effect Requiring Management (AERM) - As part of the AMR process, the applicant determines any aging effects requiring management for the material and environment
 
combination in order to maintain the intended function of the component type. These
 
aging effects requiring management are listed in column five. 6.AMPs - The AMPs used to manage the aging effects requiring management are listed in column six of Table 2. 7.GALL Volume 2 Item - Each combination of component type, material, environment, AERM, and AMP that is listed in Table 2 is compared to the GALL Report, Volume 2 with
 
consideration given to the standard notes, to identify consistencies. When they are
 
identified, they are documented by noting the appropriate GALL Report, Volume 2 item
 
number in column seven of Table 2. If there is no corresponding item number in the
 
GALL Report, Volume 2, this row in column seven has "None." That way, a reviewer can
 
readily identify where there is correspondence between the plant-specific tables and the
 
GALL Report, Volume 2 tables. 8.Table 1 Item - Each combination of component, material, environment, AERM, and AMP that has an identified NUREG-1801 Volume 2 item number must also have a Table 3.x.1
 
line item reference number. The corresponding line item from Table 1 is listed in column
 
eight of Table 2. If there is no corresponding item in the GALL Report, Volume 1, this
 
row in column eight has "None." That way, the information from the two tables can be
 
correlated. 9.Notes - In order to realize the full benefit of the GALL Report, BFN has aligned the information in the Tables 3.x.2.y with the information in NUREG-1801 Volume 2 using a
 
series of notes. Notes that utilize letter designations are industry-standard notes taken
 
from the Proposed Standard License Renewal Application Format Package (Letter from
 
Alexander Marion (NEI) to Dr. P. T. Kuo (NRC), Project Number: 690, dated August 20, 2003). Notes that use numeric designations are BFN plant-specific notes.3.0.2  Staff's Review Process The staff conducted the following three types of evaluations of the AMRs and associated AMPs:  1.For items the applicant states are consistent with the GALL Report, the staff conducted an audit. 2.For items the applicant states are consistent with the GALL Report with exceptions, the staff conducted an audit of the item and of the applicant's technical justification for the
 
exceptions. 3.For items that are not consistent with the GALL Report, the staff conducted a technical review.3.0.2.1  Review of AMPs For those AMPs for which the applicant claimed consistency with the GALL AMPs, the staff conducted either an audit or a technical review to verify that the applicant's AMPs were
 
consistent with the AMPs in the GALL Report. For each AMP that had one or more deviations, the staff evaluated each deviation to determine: (1) whether the deviation was acceptable; and
 
(2) whether the AMP, as modified, would adequately manage the aging effect(s) for which it was 3-5 credited. For AMPs that were not evaluated in the GALL Report, the staff performed a full review to determine the adequacy of the AMPs. The staff evaluated the AMPs against the
 
following 10 program elements defined in SRP-LR Appendix A. 1.Scope of Program - Scope of the program should include the specific structures and components subject to an AMR for license renewal. 2.Preventive Actions - Preventive acti ons should prevent or mitigate aging degradation. 3.Parameters Monitored or Inspected - Parameters monitored or inspected should be linked to the degradation of the particular structure or component intended functions(s). 4.Detection of Aging Effects - Detection of aging effects should occur before there is a loss of structure or component intended functions(s). This includes aspects such as method
 
or technique (i.e., visual, volumetric, surface inspection), frequency, sample size, data
 
collection, and timing of new/one-time inspections to ensure a timely detection of aging
 
effects. 5.Monitoring and Trending - Monitoring and trending should provide predictability of the extent of degradation, as well as timely corrective or mitigative actions. 6.Acceptance Criteria - Acceptance criteria, against which the need for corrective action will be evaluated, should ensure that the structure or component intended function(s) are
 
maintained under all CLB design conditions during the period of extended operation. 7.Corrective Actions - Corrective actions, including root cause determination and prevention of recurrence, should be timely. 8.Confirmation Process - Confirmation process should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective. 9.Administrative Controls - Administrati ve controls should provide a formal review and approval process. 10.Operating Experience - Operating exper ience of the AMP, including past corrective actions resulting in program enhancements or additional programs, should provide
 
objective evidence to support the conclusion that the effects of aging will be managed
 
adequately so that the structure and component intended function(s) will be maintained
 
during the period of extended operation.
Details of the staff's audit evaluation of program elements (1) through (6) are documented in the BFN audit and review report and are summarized in SER Section 3.0.3.
The staff reviewed the applicant's Corrective Action Program and documented its evaluations in SER Section 3.0.4. The staff's evaluation of the Corrective Action Program included
 
assessment of the following program elements: (7) corrective actions, (8) confirmation process, and (9) administrative controls.
The staff reviewed the information concerning t he (10) operating experience program elements and documented its evaluation in the BFN audit and review report. The staff also included a
 
summary of the program in SER Section 3.0.3.
3-6 The staff reviewed the updated final safety analysis report (UFSAR) supplement for each AMP to determine if it provided an adequate description of the program or activity, as required by
 
10 CFR 54.21(d).3.0.2.2  Review of AMR Results Table 2 of the LRA contains information concerning whether or not the AMRs align with the AMRs identified in the GALL Report. For a given AMR in Table 2, the NRC staff reviewed the
 
combination of intended function, material, environment, AERM, and AMP for a particular
 
component type within a system. The Table 2 AMRs that correlate with an AMR in the GALL Report are identified by a reference item number in column seven, "GALL, Volume 2 Item." The eighth column, "Table 1 Item," provides a reference number that indicates the corresponding
 
row in Table 1.
The staff conducted an audit to verify the appropriateness of the applicant's AMR correlations to the GALL Report. A blank column seven indicates that the applicant was unable to locate an
 
appropriate corresponding AMR in the GALL Report. The staff conducted a technical review of
 
those Table 2 AMRs that are not consistent with the GALL Report.
3.0.2.3  UFSAR Supplement Consistent with the SRP-LR, for the AMRs and associated AMPs that it reviewed, the staff also reviewed the UFSAR supplement that summarizes the applicant's programs and activities for
 
managing the effects of aging for the period of extended operation, as required by
 
10 CFR 54.21(d).
3.0.2.4  Documentation and Documents Reviewed In performing its review, the staff relied heavily on the LRA, the LRA supplements, the SRP-LR, and the GALL Report.
Also, during the onsite audit, the staff examined the applicant's justification, as documented in the staff's BFN audit and review report, to verify that the applicant's activities and programs will
 
adequately manage the effects of aging on SCs. The staff also conducted detailed discussions
 
and interviews with the applicant's license renewal project personnel and others with technical
 
expertise relevant to aging management.
 
====3.0.3 Aging====
Management Programs Table 3.0.3-1 presents the AMPs credited by the applicant and described in LRA Appendix B.
The table also indicates the GALL Report with which the applicant claimed its AMP was
 
consistent (if applicable) and the SSCs that credit the AMP for managing or monitoring aging.
 
The section of the SER, in which the staff's evaluation of the program is documented, is also
 
provided.
3-7 Table 3.0.3-1  BFN's Aging Management ProgramsBFN's AMP(LRA Section)GALL ComparisonGALLAMP(s)LRA Systems or StructuresThat Credit the AMP Staff's SER SectionExisting AMPs Electrical Cables Not Subject to 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements Used in
 
Instrumentation Circuits
 
Program (B.2.1.2)Not consistent -
exceptions takenXI.E2Electrical and instrumentation and controls 3.0.3.2.1 ASME Code Section XISubsections IWB, IWC, and IWD Inservice
 
Inspection Program (B.2.1.4)ConsistentXI.M1Reactor vessel, internals, andreactor coolant system;
 
containments, structures, and
 
component supports; engineered safety features systems; auxiliary systems; steam and power conversion systems 3.0.3.1.3Chemistry Control Program (B.2.1.5)Not consistent -
exceptions and
 
enhancements
 
takenXI.M2Reactor vessel, internals, andreactor coolant system; engineered safety features systems; auxiliary systems; steam and power conversion systems; containments, structures, and component
 
supports 3.0.3.2.2 Reactor Head Closure Studs Program (B.2.1.6)ConsistentXI.M3Reactor vessel, internals, andreactor coolant system 3.0.3.1.4Boiling Water Reactor Vessel Inside Diameter
 
Attachment Welds
 
Program (B.2.1.7)Consistent with enhancementsXI.M4Reactor vessel, internals, andreactor coolant systems 3.0.3.2.3Boiling Water ReactorFeedwater Nozzle
 
Program (B.2.1.8)Consistent with enhancementsXI.M5Reactor vessel, internals, andreactor coolant systems 3.0.3.2.4Boiling Water Reactor Control Rod Drive
 
Return Line Nozzle
 
Program (B.2.1.9)ConsistentXI.M6Reactor vessel, internals, andreactor coolant systems 3.0.3.1.5 BFN's AMP(LRA Section)GALL ComparisonGALLAMP(s)LRA Systems or StructuresThat Credit the AMP Staff's SER Section 3-8Boiling Water Reactor Stress Corrosion
 
Cracking Program (B.2.1.10)Consistent with enhancementsXI.M7Reactor vessel, internals, andreactor coolant systems; engineered safety features; auxiliary systems; steam and power conversion system 3.0.3.2.5Boiling Water Reactor Penetrations Program (B.2.1.11)Consistent with enhancementsXI.M8Reactor vessel, internals, andreactor coolant systems 3.0.3.2.6Boiling Water Reactor Vessel Internals
 
Program (B.2.1.12)Consistent with enhancementsXI.M9Reactor vessel, internals, andrector coolant systems 3.0.3.2.7Thermal Aging and Neutron Irradiation
 
Embrittlement of Cast
 
Austenitic Stainless
 
Steel Program (B.2.1.14)N/AXI.M13N/A3.0.3.2.8Flow-Accelerated Corrosion Program (B.2.1.15)Consistent with enhancementsXI.M17Steam and power conversionsystems; engineered safety features systems 3.0.3.2.9 Bolting Integrity Program (B.2.1.16)
Not consistent -
exceptions takenXI.M18Reactor vessel, internals, andreactor coolant systems; engineered safety features systems; auxiliary systems; steam and power conversion systems 3.0.3.2.10Open-Cycle CoolingWater Program (B.2.1.17)Consistent with enhancementsXI.M20Auxiliary systems3.0.3.2.11Closed-Cycle CoolingWater System Program (B.2.1.18)Consistent with enhancementsXI.M21Auxiliary systems3.0.3.2.12 Inspection of OverheadHeavy Load and Light
 
Load Handling Systems Program (B.2.1.20)
Not consistent -
exceptions takenXI.M23Auxiliary systems3.0.3.2.13 Compressed Air Monitoring Program (B.2.1.21)Consistent with enhancementsXI.M24Auxiliary systems; steam andpower conversion systems 3.0.3.2.14 BWR Reactor WaterCleanup System
 
Program (B.2.1.22)Consistent with enhancementsXI.M25Auxiliary systems3.0.3.2.15 BFN's AMP(LRA Section)GALL ComparisonGALLAMP(s)LRA Systems or StructuresThat Credit the AMP Staff's SER Section 3-9Fire Protection Program (B.2.1.23)
Not consistent -
exceptions and
 
enhancements
 
takenXI.M26Auxiliary systems; containments, structures, and
 
component supports 3.0.3.2.16Fire Water System Program (B.2.1.24)
Not consistent -
exceptions and
 
enhancements
 
takenXI.M27Auxiliary systems3.0.3.2.17 Aboveground CarbonSteel Tanks Program (B.2.1.26)ConsistentXI.M29Steam and power conversionsystems 3.0.3.1.6Fuel Oil Chemistry Program (B.2.1.27)
Not consistent -
exceptions takenXI.M30Auxiliary systems3.0.3.2.18 Reactor Vessel Surveillance Program (B.2.1.28)Consistent with enhancementsXI.M31Reactor vessel, internals, andreactor coolant system 3.0.3.2.19 Buried Piping andTanks Inspection
 
Program (B.2.1.31)ConsistentXI.M34Engineered safety featuresystems; auxiliary systems 3.0.3.1.9 ASME Code Section XISubsection IWE
 
Program (B.2.1.32)
Not consistent -
exceptions takenXI.S1Containments, structures, and component supports 3.0.3.2.20 ASME Code Section XISubsection IWF
 
Program (B.2.1.33)
Not consistent -
exceptions takenXI.S3Containments, structures, and component supports 3.0.3.2.2110 CFR 50 Appendix J Program (B.2.1.34)ConsistentXI.S4Contai nments, structures, and component supports 3.0.3.1.10Masonry Wall Program (B.2.1.35)Consistent with enhancementsXI.S5Containments, structures, and component supports 3.0.3.2.22 Structures Monitoring Program (B.2.1.36)Consistent with enhancementsXI.S6Containments, structures, and component supports 3.0.3.2.23 Inspection of Water-Control
 
Structures Program (B.2.1.37)Consistent with enhancementsXI.S7Containments, structures, and component supports 3.0.3.2.24Systems Monitoring Program (B.2.1.39)Plant-specificN/AReactor coolant systems;engineered safety features systems; auxiliary systems; steam and power conversion systems 3.0.3.3.1 BFN's AMP(LRA Section)GALL ComparisonGALLAMP(s)LRA Systems or StructuresThat Credit the AMP Staff's SER Section 3-10 Diesel Starting Air Program (B.2.1.41)Plant-specificN/AAuxiliary systems3.0.3.3.3 Environmental Qualification Program (B.3.1)Consistent with enhancementsX.E1Electrical and instrumentation and controls 3.0.3.2.25Fatigue Monitoring Program (B.3.2)Consistent with enhancementsX.M1Reactor vessel, internals, andreactor coolant systems;
 
containment, structures, and
 
component supports 3.0.3.2.26New AMPs Accessible Non-Environmental
 
Qualification Cables
 
and Connections
 
Inspection Program (B.2.1.1)ConsistentXI.E1Electri cal and instrumentation and controls 3.0.3.1.1 Inaccessible Medium Voltage Cables Not
 
Subject to 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements Program (B.2.1.3)ConsistentXI.E3Electri cal and instrumentation and controls 3.0.3.1.2Thermal Aging Embrittlement of Cast
 
Austenitic Stainless
 
Steel Program (B.2.1.13)N/AMain steam lineflow-restricting venturis 3.0.3.3.4One-Time Inspection Program (B.2.1.29)ConsistentXI.M32Reactor vessel, internals, andreactor coolant systems; engineered safety feature systems; auxiliary systems; steam and power conversion systems; containment, structures and component
 
supports 3.0.3.1.7 Selective Leaching of Materials Program (B.2.1.30)ConsistentXI.M33Engineered safety featuresystems; auxiliary systems; steam and power conversion systems 3.0.3.1.8 Bus Inspection Program (B.2.1.40)Plant-specificN/A3.0.3.3.2 BFN's AMP(LRA Section)GALL ComparisonGALLAMP(s)LRA Systems or StructuresThat Credit the AMP Staff's SER Section 3-11 Unit 1 Periodic Inspection Program (B.2.1.42)Plant-specificN/AUn-replaced, un-refurbished piping and components for Unit 1 only 3.0.3.3.53.0.3.1  AMPs That Are Consistent with the GALL Report, for Which Further Evaluation is Not Recommended In LRA Appendix B, the applicant identified that the following AMPs were consistent with the GALL Report:
* Accessible Non-Environmental Qualification Cables and Connections Inspection Program (B.2.1.1)
* Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program (B.2.1.3)
* ASME Code Section XI Subsections  IWB, IWC, and IWD Inservice Inspection Program (B.2.1.4)
* Reactor Head Closure Studs Program (B.2.1.6)
* Boiling Water Reactor Control Rod Drive Return Line Nozzle Program (B.2.1.9)
* Aboveground Carbon Steel Tanks Program (B.2.1.26)
* One-Time Inspection Program (B.2.1.29)
* Selective Leaching of Materials Program (B.2.1.30)
* Buried Piping and Tanks Inspection Program (B.2.1.31)
* 10 CFR 50 Appendix J Program (B.2.1.34)
During its audit and review, conducted June 21 to 25, 2004, the staff confirmed the applicant's claim of consistency with the GALL Report. As a result of this review, the staff identified issues
 
for several of the AMPs that were resolved with a docketed response from the applicant. Those
 
issues and resolutions are discussed in Sections 3.0.3.1.1 to 3.0.3.1.10, below.
3.0.3.1.1  Accessible Non-Environmental Qualification Cables and Connections Inspection Program Summary of Technical Information in the Application. The applicant's Accessible Non-Environmental Qualification (Non-EQ)
Cables and Connections Inspection Program is described in LRA Section B.2.1.1, "Accessible Non-Environmental Qualification Cables and
 
Connections Inspection Program." In the LRA, the applicant stated that this is a new program
 
that will be initiated prior to the period of extended operation. This commitment is identified on
 
the applicant's license renewal commitment list as Item No. 1. This program is consistent with GALL AMP XI.E1, "Electrical Cables and Connections Not Subject to 10 CFR 50.49
 
Environmental Qualification Requirements."
3-12 Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented
 
in the BFN audit and review report. The staff determined that this AMP is consistent with the
 
AMP described in the GALL Report, including the associated operating experience attribute.
As a result of this review, the staff identified two issues discussed below that were resolved with a docketed response from the applicant. 1.GALL AMP XI.E1 recommends that the program be written specifically to address cables and connections at plants whose configuration is such that most (if not all) cables and
 
connections installed in adverse localized environments are accessible. However, the
 
applicant's description of the Accessible Non-EQ Cables and Connections Inspection
 
Program does not address the percentage of cables in adverse localized environments at BFN that are accessible.
The applicant stated, as documented in the staff's audit and review report that, based upon a search of as designed data in the current cable routing database, greater than 50
 
percent of cables are located in accessible cable trays.
The staff found the applicant's response acceptable since more than 50 percent of the cables will be accessible for inspection, which is consistent with the recommendations for GALL AMP XI.E1. 2.The description of GALL AMP XI.E1 states that the technical basis for the sample of cables and connections selected for inspection is to be provided. However, the staff
 
noted that the description of the Accessible Non-EQ Cables and Connections Inspection
 
Program in the LRA does not address the rationale for selecting the sample of cables
 
and connections to be inspected.
In its response to the request for additional information (RAI) 3.6-6, dated December 9, 2004, the applicant stated that the scope of the program will include a representative
 
sample of accessible, insulated cables and connections within the scope of license
 
renewal will be visually inspected in adver se localized environments as identified by a review of operating experience. Selected cables and connections from accessible areas (the inspection sample) will represent, with reasonable assurance, all cables and
 
connections in adverse localized environments.
Operating Experience
: The applicant stated in the LRA that the Accessible Non-EQ Cables and Connections Inspection Program is a new program for which there is no operating experience.
 
The operating experience data associated with im plementing this program will be addressed in the applicant's Corrective Action Program. In evaluating the element, the applicant stated that
 
the implementation of the Accessible Non-EQ Cables and Connections Inspection Program will provide reasonable assurance that the applicable aging effects will be effectively managed so
 
that the structures and components within the scope of this program will continue to perform
 
their intended functions consistent with the CLB for the period of extended operation.
UFSAR Supplement. In LRA Section A.1.1, the applicant provided the UFSAR supplement for the Accessible Non-EQ Cables and Connections Inspection Program. The staff reviewed this
 
section and determined that the information in the UFSAR supplement provides an adequate
 
summary description of the program. The staff found this section of the UFSAR supplement
 
sufficient, as required by 10 CFR 54.21(d).
3-13 Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. The staff concluded that the applicant had demonstrated
 
that the effects of aging will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.1.2  Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program Summary of Technical Information in the Application. The applicant's Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program is described in LRA
 
Section B.2.1.3, "Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49
 
Environmental Qualification Requirements Program."
In the LRA, the applicant stated that this is a new program that will be initiated prior to the period of extended operation. This program isconsistent with GALL AMP XI.E3, "Inaccessible Medium Voltage Cables Not Subject to
 
10 CFR 50.49 Environmental Qualification Requirements."
The applicant stated that the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program will manage the aging effects of inaccessible medium-voltage cables that are not subject to the EQ requirements of 10 CFR 50.49 and are exposed to
 
adverse localized environments caused by moisture while energized. The applicant also stated
 
that the specific type of test performed will be determined prior to the initial test and will be a
 
proven test for detecting deterioration of the insulation system due to wetting. The test will be as
 
described in Electric Power Research Institute (EPRI) TR-103834-P1-2 or will be a test that is
 
state-of-the-art at the time of program implementation.
The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program is a conditi on monitoring program in which medium voltage cables that are installed in underground conduit duct banks and that perform an intended
 
function within the scope of license renewal (such as the medium voltage cables to the residual
 
heat removal service water (RHRSW) pumps) will be tested to provide an indication of the
 
condition of the conductor insulation. The specific type of test performed will be determined prior
 
to the initial test and will be a proven test for detecting deterioration of the
 
insulation system due to wetting.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in LRA Section B.2.1.3, regarding the applicant's demonstration of the Inaccessible
 
Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB throughout the period of extended
 
operation.
The staff's review of LRA Section B.2.1.3 identified an area in which additional information was necessary to complete the review of the applicant's program elements. The applicant responded
 
to the staff's RAI as discussed below.
3-14 In RAI 3.6-3, dated November 4, 2004, the staff stated it reviewed the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program credited for managing
 
the effects for non-EQ inaccessible medium voltage cables. Therefore, staff requested the
 
applicant to provide (1) a list of cables that are covered under this program, (2) any plant and/or
 
industry operating experience regarding the water-treeing phenomenon or any anticipated
 
decrease in the dielectric strength of the conductor insulation, and (3) a description of the 10
 
elements of the proposed AMP.
The staff's evaluation of the quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements are discussed below:  1.Scope of Program - In its response to the staff RAI 3.6-3 as above and by letter dated December 9, 2004, the applicant stated that medium voltage cables that are installed in
 
underground conduit duct banks and that perform an in-scope intended function (such
 
as the medium voltage cables to RHRSW pumps) will also be included in this program.
 
The staff finds the above response to be acceptable since the Non-EQ Inaccessible
 
Medium voltage Cable Program will require testing of all in-scope cables included in the
 
program. 2.Preventive Actions - Periodic actions, such as inspecting for water collection in cable manholes and conduit, and draining water, as needed, will be taken to prevent cables
 
from being exposed to significant moisture. These actions will be performed as part of
 
the testing described in Parameters Monitored or Inspected. The staff finds that the
 
inspection of water collection in cable manholes and conduit at a ten year frequency is
 
not adequate. The staff indicated that the frequency of inspection for water collection in
 
cable manholes and conduit should be yearly. The staff asked the applicant to explain
 
why every ten years inspection is sufficient. On January 18, 2005, the applicant stated
 
that inspection for water collection for in-scope cable manholes and conduits will be
 
adjusted to be performed annually. Based on the above, the staff's concern is resolved. 3.Parameters Monitored or Inspected - This program will test those inaccessible medium voltage cables identified as in scope to determine the condition of the conductor
 
insulation by testing the cables. The specific type of test performed will be determined
 
prior to the initial test, and is to be a proven test for detecting deterioration of the
 
insulation system, such as power factor, partial discharge, or polarization index, as described in EPRI TR-103834-P1-2, or other testing that is state-of-art at the time. The staff finds this to be acceptable since this is consistent with the GALL XI.E3 program. 4.Detection of Aging Effects - Affected cables will be tested before the current 40-year licensing term has concluded for each unit and at least once every 10 years thereafter.
The staff finds this to be acceptable since this is consistent with the GALL XI.E3
 
program. 5.Monitoring and Trending - Trending actions are not included as part of this program because the ability to trend test results is dependent on the specific type of test chosen.
 
Test results that are trendable may be trended to provide additional information on the
 
rate of degradation. The staff finds this to be acceptable since this is consistent with GALL XI.E3 program.
3-15  6.Acceptance Criteria - During testing, cables shall meet the acceptance criteria of the test being performed. The staff finds this to be acceptable since this is consistent with the GALL XI.E3 program. 7.Operating Experience - Industry operating experience was incorporated into the license renewal process through a review of industry documents to identify aging effects and
 
mechanisms that could challenge the intended function of components within the scope
 
of this program. Review of plant-specific operating experience was also performed to
 
identify aging effects experienced. This review involved electronic database searches of
 
plant information including problem evaluation reports (PERs), staff communications, RAIs, and work orders (WOs). As a result of the search, the following documents were
 
reviewed with no new aging effects identified: Information Notice (IN) 86-49, RIS
 
2000-25, and RAIs 1554 through 1558 (Peach Bottom Units 1 and 2).
On the basis of its review of the above operating experience, the staff concluded that the applicant's program for Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ
 
Requirements Program adequately manages the agi ng effects that have been observed at the applicant's plant. Therefore, the staff's concern described in RAI 3.6-3 is resolved.
UFSAR Supplement. In LRA Section A.1.3, and subsequent LRA supplements, the applicant provided the UFSAR supplement for the applicant
's program for Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program. The staff reviewed this section
 
and determined that the information in the UFSAR supplement provides an adequate summary
 
description of the program. The staff found that this section of the UFSAR supplement met the
 
requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program and RAI response, the staff determined that those program elements for which the applicant claimed consistency
 
with the GALL Report are consistent with the GALL Report. The staff concluded that the
 
applicant had demonstrated that the effects of aging will be adequately managed so that the
 
intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement
 
for this AMP and concluded that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.1.3  ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program
 
Summary of Technical Information in the Application. The applicant's American Society ofMechanical Engineers (ASME) Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program is described in LRA Section B.2.1.4, "ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program." In the LRA, the applicant stated that this is an
 
existing program. This program is consistent with GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD."In the LRA, the applicant stated that the ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program includes periodic visual, surface, and/or volumetric
 
examination of Class 1, 2, and 3 pressure-retaining components and their integral attachments.
Requirements for ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection
 
Program are mandated by the BFN Technical Require ments Manual 3.4.3, "Structural Integrity."
3-16 Section 50.55a of 10 CFR imposes the inservice inspection requirements of the ASME CodeSection XI for Class 1, 2, and 3 pressure-retaining components and their integral attachments in
 
light-water-cooled power plants.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented
 
in the BFN audit and review report. The staff determined that this AMP is consistent with the
 
AMP described in the GALL Report, including the associated operating experience attribute.Based on its review, the staff concluded that the applicant's ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program provides reasonable assurance
 
of aging management. As a result of this review, the staff identified two issues discussed below
 
that were resolved with a docketed response from the applicant. 1.The staff noted that ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program did not indicate what the IWB, IWC, and IWD commitment will be for
 
Unit 1 restart baseline inspections, after restart, and during the extended period of
 
operation.
The applicant stated, as documented in the staff's audit and review report, that the re-baseline inspection scope includes all inspections required during a typical 10-year
 
inspection interval for Class 1, 2, and 3 components that have not been repaired or
 
replaced. The code of record for Unit 1 recovery is the 1995 Edition with Addenda through 1996 of ASME Code Section XI. Following restart, the current (suspended)
 
inservice inspection (ISI) interval will be co mpleted. The next inspection interval will meet the requirements of 10 CFR 50.55(a) at that time. For the period of extended operation, the Code edition will be consistent with 10 CFR 50.55(a) requirements for all three units.
The staff found the applicant's response acceptable on the basis that all three units will be consistent with the GALL Report during the extended period of operation and the
 
Unit 1 re-baseline program will provide reasonable assurance that the condition of Unit 1
 
piping and components is comparable to that of Units 2 and 3. 2.In LRA Section B.2.1.4, the applicant stated that currently approved relief requests and approved code cases are used. The staff noted that these are not applicable to the
 
period of extended operation and asked the applicant to confirm that the commitment to
 
implement the requirements of 10 CFR 50.55(a) for license renewal is not modified by
 
the current relief requests or implementation of currently approved code cases.
The applicant stated, as documented in the staff's audit and review report, that the commitment to implement the requirements of 10 CFR 50.55(a) for license renewal is
 
not modified by the current relief requests or implementation of currently approved Code cases; that there are currently no relief requests that extend past the 40-year period;
 
and, that relief requests that extend into the period of license renewal will be in
 
accordance with 10 CFR 50.55(a).
The staff found the applicant's response acceptable on the basis that current approved relief requests and code cases will not in any way modify the applicant's commitment to
 
implement 10 CFR 50.55a during the period of extended operation.
3-17 Operating Experience. The ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program in accordance with Subsections IWB, IWC, or IWD has been shown to be
 
generally effective in managing aging effects in Class 1, 2, or 3 components and their integral
 
attachments.
The applicant successfully identified indications of age-related degradation prior to the loss of the functions of the components, and has taken appropriate corrective actions through evaluation, repair, or replacement of the components in accordance with ASME Section XI and
 
station implementing procedures.
UFSAR Supplement. In LRA Section A.1.4, the applicant provided the UFSAR supplement forthe ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program. The
 
staff reviewed this section and determined that the information in the UFSAR supplement
 
provides an adequate summary description of the program. The staff found that this section of
 
the UFSAR supplement met the requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. The staff concluded that the applicant had demonstrated
 
that the effects of aging will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.1.4  Reactor Head Closure Studs Program
 
Summary of Technical Information in the Application. The applicant's Reactor Head Closure Studs Program is described in LRA Section B.2.1.6, "Reactor Head Closure Studs Program." In
 
the LRA, the applicant stated that this is an existing program. This program is consistent with GALL AMP XI.M3, "Reactor Head Closure Studs Program."
In the LRA, the applicant stated that the Reactor Head Closure Studs Program includes (1)inservice inspection in conformance with the requirements of the ASME Code Section XI
 
Subsection IWB, Table IWB 2500-1 (B.2.1.4), and (2) preventive measures to mitigate cracking.
 
The applicant stated that (1) the preventive measures of regulatory guide (RG) 1.65, "Materials
 
and Inspections for Reactor Vessel Closure Studs," have been implemented, and (2) approved
 
lubricants minimize the potential for cracking of the non-metal-plated reactor head closure
 
studs.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented
 
in the BFN audit and review report. The staff determined that this AMP is consistent with the
 
AMP described in the GALL Report, including the associated operating experience attribute.
Operating Experience. In LRA Section B.2.1.6, the applicant evaluated the program element operating experience and stated that stress corrosion cracking (SCC) has occurred in boiling
 
water reactor (BWR) reactor head closure studs, particularly metal-plated studs. The approved
 
lubricants used have proven to be effective in preventing seized studs or nuts. The reactor head 3-18 closure studs are not metal plated. With the lack of metal plating and preventive use of approved lubricants, the Reactor Head Closure Studs Program has been effective in reducing
 
the probability of SCC of the reactor head closure studs.
UFSAR Supplement. In LRA Section A.1.6, the applicant provided the UFSAR supplement for the Reactor Head Closure Studs Program. The staff reviewed this section and determined that
 
the information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found that this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. The staff concluded that the applicant had demonstrated
 
that the effects of aging will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.1.5  Boiling Water Reactor Control Rod Drive Return Line Nozzle Program
 
Summary of Technical Information in the Application. The applicant's BWR Control Rod Drive Return Line Nozzle Program is described in LRA Section B.2.1.9, "Boiling Water Reactor
 
Control Rod Drive Return Line Nozzle Program." In the LRA, the applicant stated that this is an
 
existing program. This program is consistent with GALL AMP XI.M6, "BWR Control Rod Drive Return Line Nozzle."
In the LRA, the applicant stated that the BWR Control Rod Drive Return Line Nozzle Programincludes (1) an inservice inspection in accordance with the ASME Code Section XI
 
Subsection IWB. This inspection requirement is implemented by the ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Ins pection Program, and (2) system modifications to mitigate cracking. The CRD return lines have been modified to meet the recommendations of
 
NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking."
 
The applicant stated that the CRD return lines now return to the reactor water cleanup system
 
piping, the CRD return line reactor vessel nozzle piping has been removed, and the reactor
 
vessel nozzles have been capped.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented
 
in the BFN audit and review report. The staff determined that this AMP is consistent with the
 
AMP described in the GALL Report, except for the staff issue described below that was
 
resolved with a docketed response from the applicant.
The staff questioned why Units 2 and 3 perform an enhanced visual test (EVT)-1 of the inner radius instead of the Code-specified volumetric exam. The applicant stated, as documented in
 
the staff's audit and review report, that the nozzle-to-vessel weld and inner radius are inspected in accordance with ASME Code Section XI, ISI Program, Subsection IWB, Category B-D
 
requirements. Units 2 and 3 perform an EVT-1 of the inner radius instead of the Code-specified
 
volumetric exam, as approved by Requests for Relief 2-ISI-16 and 3-ISI-14. The applicant 3-19 indicated that an ultrasonic (UT) exam of both the nozzle-to-vessel weld and the inner radius is currently performed for Unit 1. Relief requests will not extend into the period of extended
 
operation. The staff found the applicant's response regarding the current inspections performed
 
for all three BFN units acceptable.
In the LRA, the applicant stated that system modifications to mitigate cracking are in progress.
The CRD return lines have been modified to meet the recommendations of NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive (CRD) Return Line Nozzle Cracking." The CRD
 
return lines now return to the reactor water cleanup system piping. The CRD return line reactor
 
vessel nozzle piping has been removed, and the reactor vessel nozzles have been capped. The
 
staff noted that the capped CRD return line nozzles are not subject to cyclic loads from thermal
 
stratification and striping. Therefore, they are not susceptible to cracking due to cyclic loading
 
and do not impact AMR review. The staff found the evaluation acceptable.
Based on its review, the staff concluded that the applicant's Boiling Water Reactor Control Rod Drive Return Line Nozzle Program provides r easonable assurance of management of inservice inspection and implementation of preventive meas ures to mitigate cracking. The staff found this AMP acceptable. It conforms to the recomm ended program description, program elements, and acceptance criteria for the Boraflex monitoring program, as discussed in GALL AMP XI.M6,"BWR Control Rod Drive Return Line Nozzle Program." Operating Experience. After implementation of the recommendations of NUREG-0619, BFN has operated for over twenty years with no significant CRD return line reactor vessel nozzle issues.
 
The plant-specific operating experience and staff evaluation are shown in SER
 
Section 3.1.2.3.10.
UFSAR Supplement. In LRA Section A.1.9, the applicant provided the UFSAR supplement for the BWR Control Rod Drive Return Line Nozzle Program. The staff reviewed this section and
 
determined that the information in the UFSAR supplement provides an adequate summary
 
description of the program. The staff found that this section of the UFSAR supplement met the
 
requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. The staff concluded that the applicant had demonstrated
 
that the effects of aging will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.1.6  Aboveground Carbon Steel Tanks Program
 
Summary of Technical Information in the Application. The applicant's Aboveground Carbon Steel Tanks Program is described in LRA Section B.2.1.26, "Aboveground Carbon Steel Tanks
 
Program." In the LRA, the applicant stated that this is an existing program. This program isconsistent with GALL AMP XI.M29, "Aboveground Carbon Steel Tanks Program."
3-20 In the LRA, the applicant stated that the program includes preventive measures to mitigate corrosion by protecting the external surface of carbon steel tanks with paint or coatings in
 
accordance with standard industry practice. The flat-bottomed condensate storage tanks sit on
 
beds of compacted sulfur-free oiled sand. The applicant also stated that it condition monitors for
 
degradation by performing periodic inspections in accordance with the 10 CFR 50.65
 
Maintenance Rule Program. The applicant stated that activities to ensure that significant
 
degradation in inaccessible tank bottoms is not occurring by performing a one-time inspection.
 
A one-time inspection, in accordance with the One-Time Inspection Program (B.2.1.29), will be
 
performed prior to entering the period of extended operation and will consist of thickness
 
measurements of flat-bottomed tanks' bottom surface.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented
 
in the BFN audit and review report. The staff determined that this AMP is consistent with the
 
AMP described in the GALL Report, except for the staff issue described below in subsection
 
"UFSAR Supplement" that was resolved with a docketed response from the applicant.
Operating Experience. Some external corrosion problems have been reported on carbon steel tanks. Corrective actions have been implemented prior to loss of intended function.
UFSAR Supplement. In LRA Section A.1.23, the applicant provided the UFSAR supplement for the Aboveground Carbon Steel Tanks Program. The staff reviewed this section and determined
 
that the information in the UFSAR supplement does not identify a one-time inspection in
 
accordance with the One-Time Inspection Program to take thickness measurements of
 
flat-bottomed tanks' bottom surface prior to entering the period of extended operation. This is
 
identified as an element of the program in LRA Section B.2.1.26. Therefore, the staff could not
 
confirm that the UFSAR supplement provides an adequate summary description of the program, as identified in the SRP-LR UFSAR supplement table, and as required by 10 CFR 54.21(d). The
 
staff requested that the applicant provide additional information to resolve this issue. The staff
 
followed this request for additional information in a follow up call with the applicant on April 7, 2005.In its response, by letter May 25, 2005, the applicant confirmed the following, which resolves the staff issue:
The One-Time Inspection Program (B.2.1.29) has been revised to specifically identify ultrasonic thickness measurements of the fuel oil storage tank bottom surfaces to ensure
 
that significant degradation is not occurring. To implement this change, the "Program
 
Description" section of LRA Appendix B.2.1.29, One-Time Inspection Program, has been
 
revised to include the following item: "thickness measurements of tank bottoms to
 
ensure that significant degradation is not occurring for those tanks specified in the Fuel
 
Oil Chemistry Program (B.2.1.27) and the Aboveground Carbon Steel Tanks Program (B.2.1.26)." The staff considers the issue resolved.
Conclusion. On the basis of its review and audit of the applicant's program, and the RAI response that those program elements for which the applicant claimed consistency with the
 
GALL Report are consistent with the GALL Report, the staff concluded that the applicant
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB for the period of extended operation, as 3-21 required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.1.7  One-Time Inspection Program
 
Summary of Technical Information in the Application. The applicant's One-Time Inspection Program is described in LRA Section B.2.1.29, "One-Time Inspection Program." In the LRA, the
 
applicant stated that this is a new program. This program is consistent with GALL AMP XI.M32,"One-Time Inspection."
In the LRA, the applicant stated that the One-Time Inspection Program will include measures to verify that unacceptable degradation of any reac tor system component is not occurring; thereby validating the effectiveness of existing AMPs or confirming that there is no need to manage
 
aging-related degradation for the period of extended operation.
LRA Section B.2.1.29 states that the elements of the One-Time Inspection Program will include:
* Determination of the sample size based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience.
* Identification of the inspection locations in the SSCs based on the aging effect.
* Determination of the examination technique, including acceptance criteria that would be effective in managing the aging effect for which the component is examined.
 
Nondestructive techniques will generally be used; however, in some circumstances (e.g.,small bore RCPB), destructive testing will be utilized if samples become available.
* Evaluation of the need for follow-up examinations to monitor the progression of any aging degradation. When one-time inspections fail to meet the established acceptance
 
criteria, the Corrective Action Program will be used to schedule, track, and trend
 
appropriate corrective actions and follow-up inspections.
LRA Section B.2.1.29 states that the One-Time Inspection Program will include the one-time inspections of SSCs that are identified generally in LRA Chapter 3.0 and in an AMR, such as:
* reactor coolant pressure boundary piping, valves, tubing, restricting orifices, and fittings less than 4-inch nominal pipe size (NPS 4) exposed to reactor coolant for loss of
 
material and cracking
* ventilation duct work for loss of material and elastomer degradation/deterioration
* flexible connections for loss of material, cracking, and elastomer degradation/deterioration
* heat exchangers for loss of material, cracking, and biofouling
* various fittings, piping, valves, pumps, strainers, tanks, traps, tubing, expansion joints, fan housings, fire dampers, and heaters for loss of material cracking, and biofouling.
3-22 The One-Time Inspection Program will be completed before the end of the current operating license term. The schedule of the inspection will be completed in a way that minimizes its
 
impact on plant operations; however, the inspecti on will not be scheduled so early in the current operating license term that will preclude questions on potential aging effects that may surface at
 
the end of the current licensing period.
The applicant, in evaluating the AMP, stated that implementation of the One-Time Inspection Program will provide reasonable assurance that the aging effects will be managed so that the
 
systems and components within the scope of this program will continue to perform their intended functions consistent with the CLB for the period of extended operation.
 
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented
 
in the BFN audit and review report. The staff determined that this AMP is consistent with the
 
AMP described in the GALL Report, including the associated operating experience attribute.
Operating Experience. The One-Time Inspection Program is new. Therefore, no programmatic operating experience is available.
UFSAR Supplement. In LRA Section A.1.26, the applicant provided the UFSAR supplement for the One-Time Inspection Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found that this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. The staff concluded that the applicant had demonstrated
 
that the effects of aging will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.1.8  Selective Leaching of Materials Program
 
Summary of Technical Information in the Application. The applicant's Selective Leaching of Materials Program is described in LRA Section B.2.1.30, "Selective Leaching of Materials
 
Program." In the LRA, the applicant stated that this is a new program. This program is consistent with GALL AMP XI.M33, "Selective Leaching of Materials."
The Selective Leaching of Materials Program consists of visual inspections and hardness measurements on selected components susceptible to selective leaching. The materials of
 
construction for these components may include cast iron, brass, bronze, or aluminum bronze.
 
These components may be exposed to a raw water, treated water, or ground water
 
environment. The Selective Leaching of Materi als Program will perform one-time visual inspections and hardness measurements of repr esentative components from those components identified in this LRA's AMR results. The Selective Leaching of Materials Program will be 3-23 completed prior to entering the period of extended operation. The selection, inspection, and measurement techniques will be consistent with i ndustry practice at the time of implementation.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented
 
in the BFN audit and review report. The staff determined that this AMP is consistent with the
 
AMP described in the GALL Report, including the associated operating experience attribute.
Operating Experience. In the LRA Section B.2.1.30 the applicant evaluated the program element operating experience and stated that the Selective Leaching of Materials Program is a
 
new program. No operating experience is available.
UFSAR Supplement. In LRA Section A.1.27, the applicant provided the UFSAR supplement for the Selective Leaching of Materials Program. The staff reviewed this section and determined
 
that the information in the UFSAR supplement provides an adequate summary description of
 
the program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. The staff concluded that the applicant had demonstrated
 
that the effects of aging will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.1.9  Buried Piping and Tanks Inspection Program Summary of Technical Information in the Application. The applicant's Buried Piping and Tanks Inspection Program is described in LRA Section B.2.1.31, "Buried Piping and Tanks Inspection
 
Program." In the LRA, the applicant stated that this is an existing program. This program isconsistent with GALL AMP XI.M34, "Buried Pipes and Tanks Inspection."
There are no buried tanks identified within the scope of license renewal. The Buried Piping and Tanks Inspection Program includes (1) preventiv e measures to mitigate corrosion by applying external coatings and wrappings in accordance with standard industry practices, and (2)
 
condition monitoring to manage the effects of corrosion. The applicant stated that buried piping
 
is inspected when excavated for any reason, typically for maintenance. The inspections are
 
performed as part of the 10 CFR 50.65 Maintenance Rule Program. The inspections provide for
 
determination of degradation due to the loss of, or damage to, the protective coatings and
 
wraps used for corrosion control on buried pipe external surfaces. The inspections also include
 
connections and joints for signs of separation, signs of environmental degradation, signs of
 
leakage, and appreciable settlement between piping segments.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented
 
in the BFN audit and review report. The staff determined that this AMP is consistent with the 3-24 AMP described in the GALL Report, except for the staff issue, described below, that concerned inspection of buried piping and that was resolved with a docketed response from the applicant.
The staff noted that the applicant relied solely on opportunistic inspections to check buried piping. If there were not any opportunistic inspections, the buried pipe would not be inspected.
 
Therefore, the staff requested that the applicant agree to inspect the buried piping within 10
 
years after entering the period of extended operation, unless conclusive opportunistic
 
inspections that provide a representative samp le have occurred within this 10-year period.
Before the tenth year, BFN should perform an engineering evaluation to determine if sufficient
 
inspections have been conducted to draw a conclusion regarding the ability of the underground
 
coatings to protect the underground piping systems from degradation. If it is found that sufficient
 
inspections have not occurred to draw a conclusion regarding the underground coatings, BFN
 
should conduct a focused inspection to allow that conclusion to be reached. The staff followed
 
this request for additional information in a follow up call with the applicant on April 7, 2005.
In its response dated May 25, 2005, the applicant clarified the staff issue as follows:
Buried piping within the scope of the Buried Piping and Tanks Program will be inspected when they are excavated for maintenance or when those components are exposed for
 
any reason. BFN will perform an inspection of buried piping within ten years after
 
entering the period of extended operation, unless an opportunistic inspection has
 
occurred within this ten-year period. Before the tenth year, BFN will perform an
 
engineering evaluation to determine if sufficient inspections have been conducted to
 
draw a conclusion regarding the ability of the underground coatings to protect the
 
underground piping from degradation. If not, BFN will conduct a focused inspection to
 
allow that conclusion to be reached. Sections A.1.28 and B.2.1.31 are modified as
 
described below to implement this change: Paragraph (b) of LRA Appendix A.1.28, Buried Piping and Tanks Inspection Program, and paragraph (b) of the "Program
 
Description" section of Appendix B.2.1.31, Buried Piping and Tanks Inspection Program
 
have been revised to include the following statement: "Before the tenth year of extended
 
operation, BFN will perform an engineering evaluation to determine if sufficient
 
inspections have been conducted to draw a conclusion regarding the ability of the
 
underground coatings to protect the underground piping from degradation. If not, BFN
 
will conduct a focused inspection to allow that conclusion to be reached.
Operating Experience. Review of the operating experience identified no concerns relating to the corrosion of external surfaces of buried piping or components. Several instances of buried
 
piping replacement were identified resulting from internal corrosion or microbiological fouling or
 
degradation. There are no buried tanks that are within the scope of license renewal.
UFSAR Supplement. In LRA Section A.1.28, the applicant provided the UFSAR supplement for the Buried Piping and Tanks Inspection Program. The staff reviewed this section and
 
determined that the information in the UFSAR supplement provides an adequate summary
 
description of the program. The staff found this section of the UFSAR supplement net the
 
requirements of 10 CFR 54.21(d).
3-25 Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. The staff concluded that the applicant had demonstrated
 
that the effects of aging will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.1.10  10 CFR 50 Appendix J Program
 
Summary of Technical Information in the Application. The applicant's 10 CFR 50 Appendix J Program is described in LRA Section B.2.1.34, "10 CFR 50 Appendix J Program." In the LRA, the applicant stated that this is an existing progr am. This program is consistent with GALL AMPXI.S4, "10 CFR Part 50, Appendix J."
The 10 CFR 50 Appendix J Program monitors leakage rates through the containment pressure boundary (including the drywell and torus, penetrations, fittings, and other access openings) in
 
order to detect degradation of the primary containment pressure boundary. Seals, gaskets, and
 
bolted connections are also monitored. Type A and Type B containment leak-rate tests are
 
performed in accordance with the regulations in 10 CFR 50 Appendix J Option B; and the
 
guidance provided in RG 1.163, "Performanc e-Based Containment Leak-Testing Program";
NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50
 
Appendix J." The 10 CFR 50 Appendix J Program requirements are mandated by Technical
 
Specification (TS) 5.5.12, Primary Containment Leakage Rate Testing Program. Additional
 
requirements for testing the containment ar e mandated by the following TS surveillance requirements: SR 3.6.1.1.1, SR 3.6.1.2.1, SR 3.6.1.3.10, and SR 3.6.1.3.11.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented
 
in the BFN audit and review report. The staff determined that this AMP is consistent with the
 
AMP described in the GALL Report, including the associated operating experience attribute.
Operating Experience. In LRA Section B.2.1.34, the applicant evaluated the program element operating experience and stated that testing in accordance with 10 CFR 50 Appendix J has
 
been effective in monitoring the pressure integrity of the primary containment boundaries
 
industry-wide and at BFN. The staff concurred with the applicant's evaluation.
UFSAR Supplement. In LRA Section A.1.31, the applicant provided the UFSAR supplement for the 10 CFR 50 Appendix J Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. The staff concluded that the applicant had demonstrated
 
that the effects of aging will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB for the period of extended operation, as required by 3-26 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).3.0.3.2  AMPs That Are Consistent with the GALL Report with Exceptions or Enhancements In LRA Appendix B, the applicant identified that the following AMPs were, or will be, consistent with the GALL Report, with exceptions or enhancements:
* Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program (B.2.1.2)
* Chemistry Control Program (B.2.1.5)
* Boiling Water Reactor Vessel Inside Diameter Attachment Welds Program (B.2.1.7)
* Boiling Water Reactor Feedwater Nozzle Program (B.2.1.8)
* Boiling Water Reactor Stress Corrosion Cracking Program (B.2.1.10)
* Boiling Water Reactor Penetrations Program (B.2.1.11)
* Boiling Water Reactor Vessel Internals Program (B.2.1.12)
* Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program (B.2.1.14)
* Flow-accelerated Corrosion Program (B.2.1.15)
* Bolting Integrity Program (B.2.1.16)
* Open-cycle Cooling Water System Program (B.2.1.17)
* Closed-cycle Cooling Water System Program (B.2.1.18)
* Inspection of Overhead Heavy Load and Light Load Handling Systems Program (B.2.1.20)
* Compressed Air Monitoring Program (B.2.1.21)
* BWR Reactor Water Cleanup System Program (B.2.1.22)
* Fire Protection Program (B.2.1.23)
* Fire Water System Program (B.2.1.24)
* Fuel Oil Chemistry Program (B.2.1.27)
* Reactor Vessel Surveillance Program (B.2.1.28)
* ASME Section XI Subsection IWE Program (B.2.1.32)
* ASME Section XI Subsection IWF Program (B.2.1.33)
* Masonry Wall Program (B.2.1.35)
* Structures Monitoring Program (B.2.1.36)
* Inspection of Water-control Structures Program (B.2.1.37) 3-27
* Environmental Qualification Program (B.3.1)
* Fatigue Monitoring Program (B.3.2)
For AMPs that the applicant claimed are consistent with the GALL Report, with exceptions or enhancements, the staff performed an audit to confirm that those programs were indeed
 
consistent. The staff also reviewed the exceptions and enhancements to the GALL Report to
 
determine whether they were acceptable and adequate. The results of the staff's audit and
 
reviews are documented in the following sections.
3.0.3.2.1  Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program Summary of Technical Information in the Application. The applicant's Electrical Cables Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program is
 
described in LRA Section B.2.1.2, "Electrical Cables Not Subject to 10 CFR 50.49
 
Environmental Qualification Requirements Used in Instrumentation Circuits Program." In the LRA, the applicant stated that this is an existing program. This program is consistent, with exception, with GALL AMP XI.E2, "Electrical Cables Not Subject to 10 CFR 50.49
 
Environmental Qualification Requirements Used in Instrumentation Circuits."
In the LRA, the applicant stated that the Electrical Cables Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program will provide reasonable assurance that the intended functions of the neutron monitoring local power range monitor (LPRM) circuits
 
exposed to adverse, localized environments caus ed by heat, radiation, and moisture can be maintained consistent with the CLB through the period of extended operation.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the exceptions and their
 
justifications to determine whether the AMP, with exceptions, remains adequate to manage the
 
aging effects for which it is credited.
The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the AMPbases documents against GALL AMP XI.E2 for consistency.
The staff noted that the LRA credits the EQ Program for managing aging effects for radiation monitoring system cables within the scope of license renewal. The EQ Program covers certain electrical components that are important to safety and could be exposed to harsh environment accident conditions. Since portions of the radiation monitoring cables are not exposed to a
 
harsh environment, the staff inquired in RAI 2.
5-2, below, whether all radiation monitoring cables within the scope of license renewal, located both inside and outside the containment, are
 
covered by the EQ Program. The applicant stated, as documented in the staff's audit and review
 
report, that all high-range radiation monitoring cables are included in the EQ Program, regardless of their location, in mild or harsh areas of the plant. The staff found the applicant's
 
response acceptable on the basis that all of the high-range radiation monitoring cables are
 
included in the EQ Program.
3-28 The staff's review of LRA Section B.2.1.2 identified an area in which additional information was necessary to complete the review of the applicant's program elements. The applicant responded
 
to the staff's RAI as discussed below.
During the audit, the staff also noted that the applicant's AMP is limited to managing the neutron monitoring local power range monitoring circuits. Not included in the scope of Electrical Cables
 
Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program are
 
nuclear instrumentation cables used in circuits for the SRM, intermediate range monitor (IRM),
average power range monitor (APRM), rod block monitor (RBM), and traversing in-core probe (TIP). The staff considers the IRM system to be safety-related (SR) at all BWRs and the IRM is
 
part of the plant's TSs. The staff pursued this issue with the applicant and requested additional
 
clarifications in RAI 2.5-2, see SER Section 2.5.1.2 Based on its response and additional discussions with the staff, the applicant concurred that the IRM instrumentation circuit cables should be within the scope of license renewal because they
 
are part of the TS. Because of this inclusion, the applicant confirmed that their aging effects
 
should be managed by the Electrical Cables Not Subject to 10 CFR 50.49 EQ Requirements
 
Used in Instrumentation Circuits Program. The applicant also agreed that other accessible
 
neutron monitoring subsystem cables and connections will be managed by the Accessible
 
Non-EQ Cables and Connections Inspection Program. This inclusion impacts the scope of the
 
two AMP elements "Program Description" and "NUREG-1801 Consistency." These changes
 
have been added to the SER Appendix A commitment table, and the applicant will modify the
 
UFSAR supplement to reflect these changes. The details of the staff evaluation on RAI 2.5-2
 
are shown in SER Section 2.5.1.2.In LRA Section B.2.1.2, the applicant stated an exception to GALL AMP XI.E2. The staff evaluation of the affected GALL elements (Parameters Monitored/Inspected and Detection of
 
Aging Effects) for the acceptability of the exception is as follows:
Exception - In LRA Section B.2.1.2, the applicant takes an exception to GALL AMP XI.E2 and states that it performs a calibration procedure that implements TS requirements. The procedure is not a normal loop calibration. The procedure utilizes actual detector signals during normal
 
operation for calibration inputs. This exception impacts the following program elements, which
 
are evaluated as follows.
Parameters Monitored/Inspected (Element 3) - The parameters monitored are determined from the plant TSs and are specific to the instrumentation loop being calibrated, as documented in
 
the surveillance test procedure. The applicant in evaluating the element stated that this program
 
will monitor parameters that are required by TS s and are specific to the LPRM cable system being calibrated.
This program will monitor parameters that are required by TSs and are specific to the LPRM cable system being calibrated. In evaluating the exception regarding Parameters
 
Monitored/Inspected, the applicant stated, as documented in the staff's audit and review report, that the applicant performs a specific calibration procedure as determined from plant TSs on
 
LPRM circuits. The applicant stated that cables are part of the calibration procedure since the
 
detector is in service when the calibration is performed. In this program, review of routine
 
calibration results by appropriate personnel provide sufficient indication of the need for
 
corrective actions by monitoring key parameter s related to LPRM cable system performance.
3-29 The normal calibration frequency specified in BFN TSs provides reasonable assurance that severe aging degradation will be detected prior to loss of the cable intended function.
The staff found that this exception acceptable in t hat it will not adversely impact the ability of the AMP to manage the affects of aging since the only difference between the applicant's program and GALL AMP XI.E2 is that the applicant utilizes actual detector signals during operation to
 
calibrate the LPRM. The parameters monitored in the applicant's program are determined from the plant TSs and, therefore, the staff found this exception to be acceptable for the program
 
element.Detection of Aging Effects (Element 4) - Calibration provides sufficient indication of the need for corrective actions by monitoring key par ameters and providing trending data based on acceptance criteria related to instrumentation-loop performance. The normal calibration
 
frequency specified in the plant TSs provides reasonable assurance that severe aging
 
degradation will be detected prior to loss of the cable intended function. The first tests for
 
license renewal are to be completed before the period of extended operation.
In evaluating the exception regarding Detection of Aging Effects, the applicant stated that routine calibration results will provide adequate and timely indication of the need for corrective
 
actions by monitoring key parameters related to LPRM cable system performance. The normal calibration frequency specified in TSs provides reasonable assurance that severe aging
 
degradation will be detected prior to loss of the cable intended function. Calibrations will
 
continue through the period of extended operation at the required frequency as specified in the
 
TSs.As discussed above, in response to the staff's inquiry regarding the difference between theapplicant's calibration procedure and that specified in GALL AMP XI.E2, the applicant stated
 
that it performs a specific calibration procedure as determined from plant TSs on LPRM circuits.
 
The normal calibration frequency specified in BFN TSs provides reasonable assurance that
 
severe aging degradation will be detected prior to loss of the cable intended function.
The staff found that this exception will not adver sely impact the ability of this AMP to manage the effects of aging since the only difference between the applicant's program and GALL AMP XI.E2 is that the applicant utilizes actual detector signals during operation to calibrate the
 
LPRM and does not perform a loop calibration. The normal calibration frequency specified in the
 
plant TSs provides reasonable assurance that severe aging degradation will be detected prior to
 
loss of the cable intended function, and the first tests for license renewal will be completed
 
before the period of extended operation. Therefore, the staff found this exception to be
 
acceptable.
Operating Experience. In LRA Section B.2.1.2, the applicant stated that industry operating experience was incorporated into the license renewal process through a review of industry
 
documents to identify aging effects and mechanisms that could challenge the intended function
 
of components, systems and structures within the scope of this program. Review of
 
plant-specific operating experience was also performed to identify aging effects experienced.
 
This review involved electronic database searches of plant information including problem
 
evaluation reports, staff communications, RAIs, and WOs. As a result, no new aging effects
 
were identified.
3-30 During the concurred audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing
 
basis. The staff concluded there is reasonable assurance that operating experience will
 
continue to be reviewed in the future to ensure that the effects of aging will be adequately
 
managed.UFSAR Supplement. In LRA Section A.1.2, the applicant provided the UFSAR supplement for the Electrical Cables Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation
 
Circuits Program. The staff reviewed this section and determined that the information in the
 
UFSAR supplement provides an adequate summary description of the program. The staff found
 
this section of the UFSAR supplement met the requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the exception and the
 
associated justifications and determined that the AMP, with the exception, is adequate to
 
manage the aging effects for which it is credited. The staff concluded that the applicant had
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP
 
and concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.2.2  Chemistry Control Program
 
Summary of Technical Information in the Application. The applicant's Chemistry Control Program is described in LRA Section B.2.1.5, "Chemistry Control Program." In the LRA, the
 
applicant stated that this is an existing program.
This program is consistent, with exceptions andan enhancement, with GALL AMP XI.M2, "Water Chemistry."
The purpose of the Chemistry Control Program is to minimize loss of material due to general, crevice, and pitting corrosion and crack initiation and growth caused by SCC. This objective is
 
achieved by periodic monitoring, control and mi tigation of known detrimental contaminants in order to ensure that their concentrations remain below the levels known to result in corrosion
 
and stress corrosion crack initiation and growth. The monitoring is consistent with the EPRI
 
guidelines for BWR reactor water chemistry, condensate and feedwater, cooling water for
 
CRDs, and other systems such as spent fuel pool water. In addition, the applicant has established an AMP consistent with GALL AMP XI.M2 "Water Chemistry."
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. The staff reviewed the two exceptions and one
 
enhancement and the applicant's justifications to determine whether the AMP, with the
 
exceptions and enhancement, remains adequate to manage the aging effects for which it is
 
credited as follows.
3-31 Exception 1. In LRA Appendix B, the applicant stated that the GALL Report recommends that water chemistry be controlled in accordance with Boiling Water Reactor Vessel Internals Project (BWRVIP)-29. BWRVIP-29 references the 1993 revision of EPRI Report TR-103515, "BWR
 
Water Chemistry Guidelines." The Chemistry Control Program is based on BWRVIP-79 EPRI Report TR-103515-R2, which is the 2000 Revision of "BWR Water Chemistry Guidelines."
This exception affects the program element, "Scope of Program," (Element 1) which is described as follows:
The program includes periodic monitoring and control of known detrimental contaminants such as chlorides, fluorides (Pressurized Water Reactors (PWRs) only),
dissolved oxygen, and sulfate concentrations below the levels known to result in loss of
 
material or crack initiation and growth. Water chemistry control is in accordance with the
 
guidelines in BWRVIP-29 (EPRI TR-103515) for water chemistry in BWRs; EPRI
 
TR-105714, Rev. 3, for primary water chemistry in pressurized water reactors (PWRs);
 
EPRI TR-102134, Rev. 3, for secondary water chemistry in PWRs; or later revisions or
 
updates of these reports as approved by the staff.
The applicant evaluated the exception applicable to the program element. The applicant stated that EPRI periodically updates the water chemistry guidelines, as new information becomes
 
available. EPRI TR-103515-R2 incorporates new information to develop proactive plant-specific water chemistry programs to minimize intergranular stress corrosion cracking (IGSCC). In the
 
"License Renewal Safety Evaluation Report for the Peach Bottom Atomic Power Station, Units 2
 
and 3" (ML030370189), the staff found EPRI TR-103515-R2 acceptable because the program is
 
based on updated industry experience and plant-specific and industry-wide operating
 
experience confirms the effectiveness of the r eactor coolant system (RCS) chemistry program.
The BFN units are similar to the Peach Bottom units. Therefore the staff conclusion reached for
 
Peach Bottom is applicable to BFN.
In evaluating the exception, the staff stated that the difference between the two revisions is due to the 2000 revision representing a more up-to-date program. It incorporates new information, which forms the basis of the proactive, plant-s pecific water chemistry procedures, which will minimize IGSCC and will provide information on water chemistry that was not available when the 1993 revision was developed. In the description of the scope of the program, the GALL
 
Report states that revisions or updates of the currently existing reports are acceptable as
 
approved by the staff. This applies to the 2000 revi sion, which was approved previously by the staff for one of the license renewal plants; therefore, the staff finds that using the 2000 revision
 
of the EPRI BWR Water Chemistry Guidelines instead of the earlier 1993 revision will not
 
negatively impact the 10 elements of the applicant
's Chemistry Control Program described in the LRA. Exception 2. In LRA Appendix B, the applicant stated that the GALL Report indicates that hydrogen peroxide is monitored to mitigate degradation of structural materials. The applicant
 
takes an exception that the Chemistry Contro l Program does not monitor for hydrogen peroxide because the rapid decomposition of hydrogen peroxide makes reliable data exceptionally
 
difficult to obtain and EPRI TR-103515-R2 Section 4.3.3, "Water Chemistry Guidelines for
 
Power Operation," does not address monitoring for hydrogen peroxide.
3-32 This exception affects the program elements, "Par ameters Monitored or Inspected" (Element 3) and "Confirmation Process," (Element 8), which are described as follows:
Parameters Monitored - The concentration of corrosive impurities listed in the EPRI guidelines discussed above, which include chlorides, fluorides (PWRs only), sulfates, dissolved oxygen, and hydrogen peroxide, ar e monitored to mitigate degradation of structural materials. Water quality (pH and conductivity) is also maintained in
 
accordance with the guidance. Chemical species and water quality are monitored by in
 
process methods or through sampling. The chemistry integrity of the samples is
 
maintained and verified to ensure that the method of sampling and storage will not cause
 
a change in the concentration of the chemical species in the samples. The guidelines in
 
BWRVIP-29 (EPRI TR-103515) for BWR reactor water recommend that the
 
concentration of chlorides, sulfates, and dissolved oxygen are monitored and kept below
 
the recommended levels to mitigate corrosion. The two impurities, chlorides and
 
sulfates, determine the coolant conductivity; dissolved oxygen, hydrogen peroxide, and
 
hydrogen determine electrochemical potential (ECP). The EPRI guidelines recommend
 
that the coolant conductivity and ECP are also monitored and kept below the
 
recommended levels to mitigate SCC and corrosion in BWR plants. The EPRI guidelines
 
in BWRVIP-29 (TR-103515) for BWR feedwater, condensate, and control rod drive water
 
recommends that conductivity, dissolved oxygen level, and concentrations of iron and
 
copper (feedwater only) are monitored and kept below the recommended levels to
 
mitigate SCC. The EPRI guidelines in BWRVIP-29 (TR-103515) also include
 
recommendations for controlling water chemis try in auxiliary systems: torus/pressure suppression chamber, condensate storage tank, and spent fuel pool.
Confirmation Process - Following corrective actions, additional samples are taken and analyzed to verify that the corrective actions were effective in returning the
 
concentrations of contaminants such as chlorides, fluorides, sulfates, dissolved oxygen, and hydrogen peroxide to within the acceptable ranges. As discussed in the appendix to
 
this report, the staff finds it acceptable to use the requirements of 10 CFR Part 50, Appendix B, in addressing the confirmation process.
The staff in evaluating the exceptions stat ed that monitoring of hydrogen peroxide is not required by any version of the EPRI BWR chemistry guidelines. Although there is a chemical
 
method for measuring hydrogen peroxide, chemical reactions occurring in sample lines result in
 
peroxide destruction before it reaches the sampling point. Obtaining meaningful results is, therefore, very difficult and not a very practical proposition. The procedure becomes even less
 
accurate with noble metals application, which is being currently practiced at the plant, due to
 
their catalytic effect on the hydrogen-oxygen reaction. However, the applicant stated that, if
 
necessary, the concentration of hydrogen peroxide can be estimated at various locations by
 
predictive radiolysis modeling. This method is acceptable to the staff, because it could provide
 
needed information.
The description of the confirmation process in the GALL Report includes a requirement for monitoring hydrogen peroxide as one of the param eters for confirming corrective actions. For the same reasons as in scope of the program element, the staff finds it justifiable not to monitor
 
hydrogen peroxide for confirmation purposes. The staff found the exceptions acceptable.
3-33 Enhancement 1. The Chemistry Control Program procedure is written to address all three units; however, Unit 1 must implement the latest revision to EPRI TR-103515-R2 guidelines prior to
 
the period of extended operation. This affect s the program element, "Scope of Program,"(Element 1), as described below.
The program includes periodic monitoring and control of known detrimental contaminants such as chlorides, fluorides (PWRs only), dissolved oxygen, and sulfate
 
concentrations below the levels known to result in loss of material or crack initiation and
 
growth. Water chemistry control is in accordance with the guidelines in BWRVIP-29 (EPRI TR-103515) for water chemistry in BWRs; EPRI TR-105714, Rev. 3, for primary
 
water chemistry in PWRs; EPRI TR-102134, Rev. 3, for secondary water chemistry in
 
PWRs; or later revisions or updates of these reports as approved by the staff.
In evaluating the element, the applicant stated that, with the implementation of this enhancement and with the exceptions noted above, the Chemistry Control Program will be consistent with the affected program element for all three units.
In evaluating the element, the enhancement stated that in order to make the Chemistry Control Program applicable to all three units in the Browns Ferry plant, the Revision 2000 of the EPRI
 
BWR Chemistry Guidelines has to be implemented in Unit 1. This will make the Chemistry
 
Control program identical for all three units. The staff finds this enhancement acceptable.
Operating Experience. In evaluating the BFN operating experience, the applicant stated that for this program element the EPRI guide line documents have been developed based on plant experience and have been shown to be effective over time with their widespread use in the
 
industry. The specific examples of BWR i ndustry operating experience are as follows:
* IGSCC has occurred in small and large-diameter BWR piping made of austenitic stainless steels and nickel-based alloys.
* Significant cracking has occurred in recirculation, core spray, residual heat removal, and reactor water cleanup systems' piping welds.
* IGSCC has also occurred in a number of vessel internal components, including the core shroud, access hole cover, top guide, and core spray spargers.
* No occurrence of SCC in piping and other components in standby liquid control systems exposed to sodium pentaborate solution has ever been reported.
As chemistry control guidelines were evolvi ng in the industry, BFN experience with RCS chemistry was similar to that of the industry. Cracking due to IGSCC was found in reactor
 
recirculation, reactor water cleanup, and jet pump instrumentation system piping.
The Chemistry Control Program is based on EPRI TR-103515-R2 (BWRVIP-79), which is the 2000 Revision of "BWR Water Chemistry Guidelines." EPRI periodically updates the water
 
chemistry guidelines, as new information becom es available. The Chemistry Control Program has incorporated new EPRI information to develop a proactive water chemistry program to minimize IGSCC.
3-34 The applicant indicated that its operating experience with reactor chemistry was similar to that of the industry. The aging effect of the components was mainly due to cracking caused by
 
IGSCC in reactor recirculation, reactor water cleanup, and jet pump instrumentation system
 
piping. The applicant has indicated that as new information becomes available the Chemistry Control Program will be updated by developing proactive water chemistry procedures aiming at
 
minimizing IGSCC.
The staff asked the applicant to provide plant-specific operating experience in staff RAI B.2.5.1-2 dated December 7, 2004, since the applicant stated in Appendix B that its
 
experience was similar to the industry experi ence described above; however, the applicant did not provide plant-specific details to substantiate the similarity.
In its response, by letter January 6, 2005, the applicant stated that a review of BFN chemistry records revealed that the EPRI Action 3 criteria were not exceeded at any time during the five
 
years considered. BFN short-term transients had no significant impact on reactor vessel and
 
RCS components. In addition, these transients had no impact on the acceptability of the
 
Chemistry Control Program as an effective agi ng management tool for the renewal term. Minor water chemistry excursions were noted. For ex ample, minor excursions above Action Level 1 occurred during unit startups. In addition, several instances of condensate demineralizer resin
 
leakage have occurred between 1999 and 2004 on Units 2 and 3 due to bleed-through of old
 
septa and deficiencies in design/installation of new septa. Once the intrusions were identified, the source of resin was isolated and sulfates were returned to normal levels. Some instances of
 
RCS sulfate concentration in Units 2 and 3 RCS exceeding Action Level 1 were observed in
 
2003 and 2004. There were no instances where Action Level 2 limits were exceeded. The
 
majority of the elevated concentrations have been due to resin intrusions. The staff found the
 
operating experience was not abnormal and was within the bounds of the industry experience
 
and, therefore, acceptable.
UFSAR Supplement. In LRA Section A.1.5, the applicant provided the UFSAR supplement for the Chemistry Control Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the exceptions and the
 
associated justifications and determined that the AMP, with exceptions, is adequate to manage
 
the aging effects for which it is credited. Also, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3-35 3.0.3.2.3  Boiling Water Reactor Vessel Inside Diameter Attachment Welds Program Summary of Technical Information in the Application. The applicant's BWR Vessel Inside Diameter (ID) Attachment Welds Program is described in LRA Section B.2.1.7 "Boiling Water
 
Reactor Vessel Inside Diameter Welds Program." In the LRA, the applicant stated that this is an
 
existing program. This program is consistent, with the enhancement, with GALL AMP XI.M4,"BWR Vessel ID Attachment Welds."
In the LRA, the applicant stated that the BWR Vessel ID Attachment Welds Program implements the inspection and evaluation re commendations of staff-approved BWRVIP-48,"Vessel ID Attachment Weld Inspection and Evaluation Guidelines," (EPRI Report TR-108724, February 1998), and the primary water chemistry recommendations in accordance with
 
BWRVIP-79, "BWR Water Chemistry Guidelines - 2000 Revision," (EPRI Report
 
TR-103515-R2, February 2000) to ensure the long-term structural integrity of inside diameter
 
attachment welds of the vessel.
The purpose of the BWR Vessel ID Attachment Welds Program is to manage the effects of crack initiation and growth due to SCC, including IGSCC, in the reactor vessel ID attachment
 
welds. The program identifies welds and their inspection frequency, flaw evaluation, and repair
 
or replacement requirements. The applicant stated that Section 7.11 of BFN Technical
 
Instruction 0-TI-365, "Reactor Pressure Vessel Internals Inspection (RPVII) Units 1, 2, and 3,"
 
identifies vessel interior wall welds that are within the scope of this AMP. They include jet pump
 
riser brace welds, core spray piping welds, and steam dryer support and feedwater (FW)
 
bracket attachment welds that use furnace-sensitized stainless steel (E308/309 or 308L/309L)
 
or alloy 182. The baseline and EVT-1, as well as re-inspection schedule, scope, and frequency
 
for these welds are consistent with BWRVIP-48 recommendations. Other non-safety related (NSR) attachment welds that are inspected in accordance with the ASME Code Section XI, Examination Category B-N-2, are steam dryer support/holddown, guide rod, FW sparger, and
 
surveillance sample holders. The applicant also stated that these examinations are coordinated with the ASME Code Section XI requirements in examination category B-N-2, which require
 
visual examination of reactor pressure vessel (RPV) internal integral attachments.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancement and its
 
justifications to determine whether the AMP, with the enhancement, remains adequate to
 
manage the aging effects for which it is credited.
In the LRA, the applicant stated that the BWR Vessel ID Attachment Welds Program will beconsistent with GALL AMP XI.M4 prior to the extended period of operation. The staff reviewed
 
the program elements (see SER Section 3.0.2.1) contained in the LRA and associated bases
 
documents, and compared them to the recommendations for GALL AMP XI.M4 for consistency.
The staff identified differences in the program elements, "Scope of Program" (Element 1),"Preventive Action" (Element (2), and "Acceptanc e Criteria" (Element 6), as discussed below.
Scope of Program - In the description of AMP XI.M4, the GALL Report recommends that BWR water chemistry control be performed in accordance with BWRVIP-29, which
 
references the 1993 revision of EPRI TR-103515, "BWR Water Chemistry Guidelines."
 
However, the BFN water chemistry program is based on BWRVIP-79, the 2000 revision 3-36 of EPRI TR-103515-R2, which uses hydrogen water chemistry (HWC) with noble metal chemical application (NMCA) to control both detrimental impurities and crack initiation
 
and growth. The staff found this difference acceptable, since BWRVIP-79 is the current
 
revision to industry practice.
Detection of Aging Effects - The staff identified a difference in the program element for detection of aging effects. BWRVIP-48 guidelines recommend EVT-1 of all SR
 
attachments and those NSR attachments identified as being susceptible to IGSCC. The recommendations in GALL AMP XI.M4 state that the EVT-1 should achieve at least 1 mil
 
wire resolution. The applicant stated that BFN's EVT-1 technique is capable of achieving
 
1/2 mil wire resolution. Since the applicant's technique is more sensitive than the
 
recommendation in the GALL Report, the staff found this difference acceptable.
Acceptance Criteria. The staff also noted that the applicant had not identified the use of BWRVIP-14, BWRVIP-59, and BWRVIP-60 in the program element for acceptance
 
criteria to evaluate crack growth in stainless steel, nickel alloy, and low-alloy steel, respectively. The applicant responded that nuclear document Nuclear Engineering
 
Design Procedure (NEDP)-23, Rev. 0, "BWR Reactor Pressure Vessel Internals
 
Inspections (RPVII)," references BWRVIP-14, BWRVIP-59, and BWRVIP-60 for the
 
evaluation of crack growth in stainless steels, nickel alloys, and low-alloy steels, respectively, as supporting documents. The staff found this acceptable.
Enhancement. In LRA Section B.2.1.7, the applicant identified one enhancement to make thisAMP consistent with GALL AMP XI.M4. The enhancement is that BWRVIP guidelines will be
 
implemented for Unit 1 prior to the period of extended operation. The staff found this
 
enhancement acceptable since it will make the applicant's program consistent for all three units.
Operating Experience. In LRA Section B.2.1.7, the applicant stated in its evaluation of the program element, "Operating Experience," that the BWR Pressure Vessel ID Weld inspection
 
program incorporates all susceptible welds. The inspections are based on operating experience, industry operating experience and various BWRVIP/EPRI Guidelines. The program schedules
 
inspections, evaluates any flaws detected, and provides for repair or replacement as appropriate. The program, as implemented, has adequately managed the reactor vessel ID
 
attachment welds.
The staff asked the applicant to describe the plant-specific operating experience relevant to the vessel ID attachment welds. The applicant provided, by its formal response dated October 8, 2004 and as documented in the staff's audit and review report, the following plant-specific
 
operating experience:
* The jet pump riser brace to vessel pad welds are inspected by Technical Instruction 0-TI-365 ("Reactor Pressure Vessel Internals Inspection (RPVII) - Units 1, 2, and 3") in
 
accordance with BWRVIP-41. The welds were baseline inspected during the 2001
 
refueling outage for Unit 2 and the 2002 and 2004 refueling outages for Unit 3. The
 
applicant did not find any reportable indications and these welds will be inspected on
 
Unit 1 prior to restart.
* The core spray piping bracket welds are inspected by 0-TI-365 in accordance with BWRVIP-18. The welds were baseline inspected during the 1999 refueling outage for 3-37 Unit 2 and the 2000 refueling outage for Unit 3. No reportable indications were found.
These welds will be inspected on Unit 1 prior to restart.
* The inspection and flaw evaluation were performed in accordance with the guidelines of BWRVIP-48. Since the implementation of t hese guidelines, for approximately 4 years, no reportable indications were found in Units 2 and 3. The applicant stated that these
 
guidelines will be implemented on Unit 1 prior to its restart.
In evaluating the element, staff concurred with the applicant that the continued implementation of the BWR Vessel ID Attachment Welds Program provides reasonable assurance that crack
 
initiation and growth will be adequately managed and the intended functions of the vessel ID
 
attachment welds will be maintained consistent with the CLB for the period of extended
 
operation. The staff found that the applicant had adequately considered operating experience, consistent with the guidance in the GALL Report. (See SER Section 3.1.2.3.7)
UFSAR Supplement. In LRA Section A.1.7, the applicant provided the UFSAR supplement for the Boiling Water Reactor Vessel ID Attachment Welds Program. The staff reviewed this section
 
and determined that the information in the UFSAR supplement provides an adequate summary
 
description of the program. The staff found this section of the UFSAR met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.4  Boiling Water Reactor Feedwater Nozzle Program
 
Summary of Technical Information in the Application.The applicant's BWR Feedwater Nozzle Program is described in LRA Section B.2.1.8 "Boiling Water Reactor Feedwater Nozzle
 
Program." In the LRA, the applicant stated that this is an existing program. This program isconsistent, with the enhancement, with GALL AMP XI.M5, "BWR Feedwater Nozzle."
In the LRA, the applicant stated that the BWR Feedwater Nozzle Program enhances the ISIsspecified in ASME Code Section XI with the recommendations of General Electric Corporation (GE) report, NE-523-A71-0594, Rev.1,"Alternate BWR Feedwater Nozzle Inspection
 
Requirements," August 1999.
The BWR Feedwater Nozzle Program manages cracking in reactor feedwater nozzles due to thermal fatigue. The program addresses BWR feedw ater nozzle cracking by implementing the recommendations of NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return
 
Line Nozzle Cracking," November 1980. LRA Section B.2.1.8 describes the details of hardware
 
modifications completed to mitigate cracking. The applicant also stated that changes to plant 3-38 operating procedures for Units 2 and 3 have been implemented and include improved feedwater control. For details of the modification implemented, refer to LRA Section B.2.1.8.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancement and its
 
justifications to determine whether the AMP, with the enhancement, remains adequate to
 
manage the aging effects for which it is credited.
In the LRA, the applicant stated that the BWR Feedwater Nozzle Program will be consistent withGALL AMP XI.M5 with the enhancement described below. The staff reviewed the program
 
elements contained in the AMP and associated bases documents, and compared them to the recommendations in GALL AMP XI.M5 for consistency.
The applicant credited GE report GE-NE-523-A71-0594, Revision 1, which has been approved by the staff, and is consistent with the GALL Report for managing crack initiation and growth in
 
the feedwater nozzle.
Enhancement. In LRA Section B.2.1.8, the applicant identified one enhancement to make thisAMP consistent with GALL AMP XI.M5. The enhancement involves Unit 1 operating procedures
 
upgraded to decrease the magnitude and frequency of FW temperature fluctuations. This
 
enhancement affects the program element "Prevent ive Action." In evaluating the element, the applicant concluded that mitigation occurs by systems modifications, such as removal of
 
stainless steel cladding and installation of improved spargers. The applicant stated that it is also
 
accomplished by changes to plant operating procedures, such as improved feedwater control
 
and rerouting of the reactor water cleanup system, to decrease the magnitude and frequency of
 
temperature fluctuations.
The staff concurred with the applicant's evaluation and finds this enhancement acceptable. It will make the applicant's program consistent for all three units.
Operating Experience. Regarding plant-specific operating experience with cracking of feedwater nozzles, the applicant stated that cracking was discovered in the RPV feedwater nozzle
 
cladding in 1977. Cladding removal and feedwater sparger replacement were performed for all
 
three units (Unit 1 - 1977, Unit 2 - 1978, Unit 3 - 1979). Since this modification was made, no
 
cracking problems have been found.
The staff concluded that implementation of the applicant's program provides reasonable assurance that cracking of feedwater nozzles is being adequately managed, such that there is
 
no loss of intended function. During the concurred audit, the staff noted that the applicant
 
incorporates internal and external plant operating experience issues into the plant Corrective
 
Action Program on a continuing basis. The staff concluded there is reasonable assurance that
 
operating experience will continue to be reviewed in the future to ensure that the effects of
 
aging will be adequately managed.
In the LRA, the applicant concluded that the BWR Feedwater Nozzle Program provides reasonable assurance that cracking aging effects in the feedwater nozzles are adequately
 
managed so that their intended functions, consistent with the CLB, are maintained during the 3-39 period of extended operation. The staff found that the applicant had adequately considered the operating experience consistent with the guidance in the GALL Report.
UFSAR. In LRA Section A.1.8, the applicant provided the UFSAR supplement for the BWR Feedwater Nozzle Program. The staff reviewed this section and determined that the information
 
in the UFSAR supplement provides an adequate summary description of the program. The staff
 
found this section of the UFSAR met the requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that implementation of the enhancem ent prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.5  Boiling Water Reactor Stress Corrosion Cracking Program
 
Summary of Technical Information in the Application. The applicant's BWR SCC Program is described in LRA Section B.2.1.10, "Boiling Water Reactor Stress Corrosion Cracking Program."
 
In the LRA, the applicant stated that this is an existing program. This program is consistent, with an enhancement, with GALL AMP XI.M7, "BWR Stress Corrosion Cracking."
In the LRA, the applicant stated that the BWR SCC Program enhances the inservice inspectionsspecified in ASME Code Section XI with the recommendations of NUREG-0313, Rev. 2, "Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure
 
Boundary Piping," 1988; NRC GL 88-01, "NRC Position on Intergranular Stress Corrosion
 
Cracking in BWR Austenitic Stainless Steel Piping," and its Supplement 1, February 1992; and
 
BWRVIP-75, "Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules,"
 
September 2000.
The purpose of BWR SCC Program is to manage IGSCC in reactor coolant pressure boundary components made of stainless steel. The comprehensive programs outlined in GL 88-01 and
 
NUREG-0313, and in the staff-approved BWRVIP-75, have been implemented and address the
 
mitigating measures for SCC and IGSCC in these components. Preventive methodologies
 
include piping replacement with IGSCC-resistant stainless steel. Preventive measures have also included heat sink welding, induction heating, and mechanical stress improvement.The ASME Code Section XI inspection and flaw evaluation methodology, enhanced by the recommendations of BWRVIP-75, is credited to detect and evaluate IGSCC. BWRVIP-75 allows
 
for modification of the inspection scope identified in the GL 88-01 program. The ASME Code Section XI, Subsections IWB, IWC, and IWD Inservice Inspection Program detects degradation, including IGSCC.
3-40 Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancement and its
 
justifications to determine whether the AMP, with the enhancement, remains adequate to
 
manage the aging effects for which it is credited.
 
In the LRA, the applicant stated that the BWR SCC Program is consistent with GALL AMP XI.M7. The staff reviewed the program elements (see SER Section 3.0.2.1) contained in
 
the AMP and associated bases documents, and compared them to the recommendations in GALL AMP XI.M7 for consistency. The staff identified a difference in the program description, as
 
well as in the program element for preventive action, as discussed below.GALL AMP XI.M7 recommends that BWR water chemistry control be performed in accordance with BWRVIP-29, which references the 1993 revision of EPRI TR-103515, "BWR Water
 
Chemistry Guidelines." The water chemistry programs are based on BWRVIP-79, which
 
references the 2000 revision of EPRI TR-103515-R2 and uses HWC with NMCA to control both
 
detrimental impurities and crack initiation and growth. The applicant stated in the LRA that BFN
 
has not applied for any relief for vessel internals component weld inspections in accordance
 
with BWRVIP-62, which allows relief for welds exposed to HWC. The staff found this difference
 
acceptable, since BWRVIP-79 is the current revision to industry practice.
Regarding the program element for preventive action, the applicant stated, as documented in the staff's audit and review report, that induction heating stress improvement and mechanical
 
stress improvement program have been used on various welds on both Units 2 and 3 as a remedy to IGSCC in austenitic stainless steel piping. However, the induction heating stress
 
improvement technique was perform ed many years prior to the issuance of BWRVIP-61, which provides guidelines for induction heating stress improvement effectiveness. As part of the applicant's response to IE Bulletin 88-01, me chanical stress improvement program will be performed on applicable welds on Unit 1 prior to restart. The BWR SCC Program will continue
 
during the period of extended operation and will implement the replacement and preventive measures as augmented by NUREG-0313, GL 88-01 and BWRVIP-75 guidelines, to mitigate
 
IGSCC. Additionally, the applicant stated that the materials in the sections of pipe exposed to fluidtemperatures greater than 200 °F are being replaced with 316 Stainless Steel NG grade
 
material, which is not susceptible to IGSCC. The criteria for the design, installation, and testing
 
associated with the replacement or removal of selected piping to limit the susceptibility to
 
IGSCC for all three BFN units is provided in general design criteria (GDC) BFN-50-779, "Replacement of Selected Piping to Limit Susceptibility to IGSCC," and has been implemented
 
for Units 2 and 3 by various design changes. Unit 1 is in the process of implementing similar
 
design changes prior to its restart.
The applicant stated that detection of leaks due to IGSCC has been performed throughinspection (Section XI and other augmented examinations, such as BWRVIP, NUREG-0619),
monitoring of drywell leakage, and the feedwater leakage detection system.
The staff noted that the applicant has not identified the use of BWRVIP-14, BWRVIP-59, and BWRVIP-60 in the program element for accept ance criteria, to evaluate crack growth in stainless steel, nickel alloy and low-alloy steel, respectively. The applicant responded that 3-41 NEDP-23, Revision 0, "BWR Reactor Pressure Vessel Internals Inspections (RPVII),"
references BWRVIP-14, BWRVIP-59, and BWRVIP-60, for evaluation of crack growth in
 
stainless steels, nickel alloys, and low-alloy steels, respectively, as supporting documents.
Since the applicant continues to use these measures in accordance with the staff-approved methodology, the staff found this acceptable.
Enhancement. In the LRA Section B.2.1.10, the applicant identified one enhancement to makethis AMP consistent with GALL AMP XI.M7. The BWR Stress Corrosion Cracking Program will
 
be implemented on Unit 1 prior to the period of extended operation. The staff found this
 
enhancement acceptable since it will make the applicant's program consistent for all three units.
Operating Experience. In the LRA, the applicant stated that, since the implementation of this program, structural integrity has been maintained by ensuring that aging effects were
 
discovered and components repaired/replaced before the loss of their intended function. For
 
Units 2 and 3, mitigation measures to prevent cra cking or dispositions of examinations that have detected cracking include: targeted replacement of existing piping with piping fabricated with
 
IGSCC-resistant material; utilizing a stress improvement process; increasing nondestructive
 
examination frequency; implementing a hydrogen water chemistry program; and, application of weld overlay reinforcement. For Unit 1, BFN is replacing the majority of Class 1 SS piping, including any weld overlay reinforcement. Pre-se rvice examinations of the replaced piping willbe performed as required by ASME Code Section XI. After restart, applicable mitigation
 
measures and nondestructive examinations will be performed in accordance with NUREG 0313, Revision 2, and GL 88-01 or the referenced BWRVIP-75 guideline.
The applicant stated that the BWR SSC Program provides reasonable assurance that SCC in stainless steel piping is adequately managed so that its intended functions, consistent with the
 
CLB, is maintained during the period of extended operation. During the onsite audit, the staff
 
noted that the applicant incorporates internal and external plant operating experience issues
 
into the plant Corrective Action Program on a continuing basis. The staff concluded there is
 
reasonable assurance that the applicant will continue to review operating experience in the
 
future to ensure that the effects of aging are adequately managed, consistent with the guidance in the GALL Report.
The staff reviewed and determined that the applicant should address the plant-specific experience related to SCC in the reactor vessel (RV) and reactor vessel internals (RVIs) at the
 
BFN units. A detailed discussion of the staff's evaluation of Boiling Water Reactor Stress
 
Corrosion Cracking Program is shown SER Section 3.1.2.3.8.
In RAI B.2.1.10-1(A), the staff requested that the applicant describe plant-specific experience related to IGSCC cracking of the stainless steel and nickel alloy components in RV and RVIs.
In its response to RAI B.2.1.10-1(A), by letter dated January 31, 2005, the applicant stated that no IGSCC had been identified in RV and its components at BFN, Units 2 and 3, with the
 
exception of guide tube/dry tube (replaced with IGSCC-resistant material as discussed in
 
Section 3.1.3.1.6.1 of the staff's SER on the AMR section). For BFN, Unit 1, the applicant
 
proposed to implement improved RCS water chem istry to mitigate IGSCC. The staff reviewed the response and finds it acceptable, because im plementation of the improved water chemistry 3-42 (AMP B.2.1.5), and ISI programs (AMP B.2.1.4) would enable the applicant to manage the aging effect due to IGSCC effectively during the extended period of operation.
In RAI B.2.1.10-1(B) the staff requested that the applicant submit information on the mitigation actions taken at BFN with respect to selection of materials that are resistant to sensitization, use
 
of special processes that reduce residual tensile stress, and monitoring of water chemistry such as discussed in GALL AMP XI.M7, "BWR Stress Corrosion Cracking." In its response to RAI B.2.1.10-1(B), by letter dated January 31, 2005, the applicant stated that mitigation efforts include selection of IGSCC-resistant materials and monitoring/control of water
 
chemistry parameters. The criteria for the design, installation, and testing associated with the
 
replacement or removal of selected RCS piping to limit the susceptibility to IGSCC is provided in
 
GDC BFN-50-779, "Replacement of Selected Piping to Limit Susceptibility to IGSCC."
Monitoring and control of chemistry parameters is controlled by AMP B.2.1.5. The staff finds
 
AMP B.2.1.5 acceptable because the program is based on updated industry experience and
 
plant-specific and industry-wide operating experience confirms the effectiveness of the RCS
 
chemistry program. The staff found that the applicant's proposed mitigation strategy would
 
ensure that the aging effect due to IGSCC in the RV and its components can be managed
 
effectively during the extended period of operation.
In RAI B.2.1.10-1(C), the staff requested that the applicant provide information concerning whether any NMCA and HWC is applied at BFN. The staff requested that the applicant confirm
 
the method of controlling HWC and any NMCA in the RV. The staff requested the applicant to
 
provide details on the methods for determining the effectiveness of HWC and NMCA by using
 
the following parameters:
(1) Electro Chemical Potential (ECP)
(2) Feedwater hydrogen flow
 
(3) Main steam oxygen content
 
(4) Hydrogen/oxygen molar ratio.
In its response to RAI B.2.1.10-1(C), by letter dated January 31, 2005, the applicant stated that BFN currently utilizes zinc addition, NMCA and HWC as part of the reactor water chemistry
 
control program. BFN does not utilize ECP probes and, therefore, alternate means are used to
 
monitor NMCA/HWC control. The acceptable alternate means are described in Section 5.4 of
 
EPRI-103515-R2. These guidelines are implemented in BFN procedure CI-13.1, Chemistry
 
Program, which specifies that the reactor water H 2/O 2 molar ratio must be greater than 4 during power operation to effectively mitigate IGSCC.
The staff agreed that implementation of HWC/NMCA should effectively mitigate IGSCC because these additions reduce the oxygen potential in RCS water. With reduced oxygen levels in the
 
RCS water the occurrence of IGSCC is minimized. The effectiveness of HWC/NMCA can be
 
maintained by using H 2/O 2 molar ratio of greater than 4, which is acceptable to the staff because this molar ratio provides adequate margin in maintaining hydrogen availability for the RV and
 
RVIs. AMP recommended by the GALL Report for managing IGSCC for the RVIs is XI.M.7,"BWR Stress Corrosion Cracking."
3-43 UFSAR Supplement. In LRA Section A.1.10, the applicant provided the UFSAR supplement for the Boiling Water Reactor Stress Corrosion Cracking Program. The staff reviewed this section
 
and determined that the information in the UFSAR supplement provides an adequate summary
 
description of the program. The staff found this section of the UFSAR supplement met the
 
requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.6  Boiling Water Reactor Penetrations Program
 
Summary of Technical Information in the Application. The applicant's BWR Penetrations Program is described in LRA Section B.2.1.11, "Boiling Water Reactor Penetrations Program."
 
In the LRA, the applicant stated that this is an existing program. This program is consistent, with an enhancement, with GALL AMP XI.M8, "BWR Penetrations."
In the LRA, the applicant stated that the BWR Penetrations Program enhances the inserviceinspections specified in ASME Code Section XI with the recommendations of BWRVIP-27, "BWR Standby Liquid Control System/Core Pl ate P/SLC Inspection and Flaw Evaluation Guidelines, (EPRI TR-107286, April 1997)" and BWRVIP-49, "Instrument Penetration Inspection
 
and Flaw Evaluation Guidelines, (EPRI TR-108695, March 1998)." Repair or replacement
 
recommendations of BWRVIP-53, "Standby Liquid Control Line Repair Design Criteria, (EPRI
 
TR-108716, March 24, 2000)" and BWRVIP-57, "Instrument Penetration Repair Design Criteria, (EPRI TR-108721, March 24, 2000)" are also implemented and are performed in accordance with ASME Code Section XI repair and replacement requirements. The program also
 
incorporates the water chemistry recommendations of BWRVIP-79, "BWR Water Chemistry
 
Guidelines, (EPRI TR-103515-R2, 2000)."
The purpose of the BWR Penetrations Program is to manage the effects of crack initiation and growth due to SCC or IGSCC in instrument and standby liquid control nozzle penetrations of the
 
reactor vessel. The program contains preventiv e measures to mitigate SCC or IGSCC. TheASME Code Section XI inservice inspections implement guidelines of BWRVIP-49 and
 
BWRVIP-27 to monitor the effects of cracking on the intended function of these penetrations.
 
BWRVIP-57 for instrumentation penetrations and BWRVIP-53 for the standby liquid control line
 
provide guidelines for repair and/or replacement as needed to maintain the ability to perform the
 
intended function.
3-44 Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancement and its
 
justifications to determine whether the AMP, with the enhancement, remains adequate to
 
manage the aging effects for which it is credited.
In the LRA, the applicant stated that the BWR Penetrations Program is consistent with GALLAMP XI.M8. The staff reviewed the program elements (SER Section 3.0.2.1) contained in the
 
AMP and associated bases documents, and compared them to those listed for GALL AMP XI.M8 for consistency.
The staff identified a difference in the program description, as well as in the program element for preventive action, as discussed below. GALL AMP XI.M7 recommends that the BWR water chemistry control be performed in accordance with BWRVIP-29, which references the 1993 revision of EPRI TR-103515, "BWR
 
Water Chemistry Guidelines." However, the water chemistry programs are based on
 
BWRVIP-79, which references the 2000 revision of EPRI TR-103515-R2 and uses HWC with
 
NMCA to control both detrimental impurities and crack initiation and growth. In the LRA, the
 
applicant stated that BFN has not applied for any relief for vessel internals component weld
 
inspections in accordance with BWRVIP-62, which allows relief for welds exposed to hydrogen
 
water chemistry. The staff found this difference acceptable. BWRVIP-79 is the current revision
 
to industry practice.
The staff also noted that the applicant has not identified the use of BWRVIP-14, BWRVIP-59, and BWRVIP-60 in the program element for acc eptance criteria to evaluate crack growth in stainless steel, nickel alloy and low-alloy steel, respectively. The applicant responded that
 
NEDP-23, Rev. 0, "BWR Reactor Pressure Vessel Internals Inspections (RPVII)," references
 
BWRVIP-14, BWRVIP-59, and BWRVIP-60, for evaluation of crack growth in stainless steels, nickel alloys, and low-alloy steels, respectively, as supporting documents. The staff found this
 
acceptable.
Enhancement. In LRA Section B.2.1.11, the applicant identified one enhancement to make thisAMP consistent with GALL AMP XI.M8. The BW RVIP guidelines will be implemented on Unit 1 prior to the period of extended operation. The staff found this enhancement acceptable since it
 
will make the applicant's program consistent for all three units.
Operating Experience. In the LRA, the applicant stated that the BWR penetration program monitors the effects of SCC/IGSCC on the intended function of the component by detection and
 
sizing of cracks by the ISI program. The ISI progr am incorporates the inspection and evaluation guidelines of BWRVIP-27 and BWRVIP-49. The BWRVIP-49 provides guidelines for instrument
 
penetrations, and BWRVIP-27 addresses the standby liquid control (SLC) system nozzle or
 
housing. Inspections are performed with BFN procedures that are part of the ISI program and incorporate the requirements of ASME Code Section XI, Table IWB-2500-1.
The applicant stated, as documented in the staff's audit and review report, that Units 2 and 3 have experienced no unacceptable conditions during t he four years since implementation of the BWRVIP-27 and BWRVIP-49 guidelines. These inspections will be implemented on Unit 1 prior 3-45 to its restart. The staff concluded that the recent operating experience provides reasonable assurance of the program's effectiveness.
During the onsite audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing basis. The
 
staff concluded there is reasonable assurance that the applicant will continue to review
 
operating experience in the future to ensure that the effects of aging are adequately managed, consistent with the guidance in the GALL Report. (See SER Section 3.1.2.3.11)
UFSAR Supplement. In LRA Section A.1.11, the applicant provided the UFSAR supplement for the BWR Penetrations Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.7  Boiling Water Reactor Vessel Internals Program
 
Summary of Technical Information in the Application. The applicant's BWR Vessel Internals Program is described in LRA Section B.2.1.12, "Boiling Water Reactor Vessel Internals
 
Program." In the LRA, the applicant stated that this is an existing program. This program isconsistent, with the enhancement, with GALL AMP XI.M9, "BWR Vessel Internals."
In the LRA, the applicant stated that the purpose of BWR Vessel Internals Program is to manage the effects of crack initiation and growth due to SCC, IGSCC, or irradiation-assisted
 
stress corrosion cracking (IASCC) in vessel internals components. The program contains
 
preventive measures to mitigate SCC or IGSCC. The ASME boiler and pressure vessel (B&PV),
Section XI, inservice inspection programs implement the BWRVIP guidelines associated with
 
BWR vessel internal components, to monitor the effects of cracking on their intended functions.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
audit and review report. Furthermore, the staff reviewed the enhancements and their
 
justifications to determine whether the AMP, with enhancements, remains adequate to manage
 
the aging effects for which it is credited.
In the LRA, the applicant stated that BWR Vessel Internals Program is consistent with GALLAMP XI.M9. The staff reviewed the program elements (see SER Section 3.0.2.1) contained in 3-46 the AMP and associated bases documents, and compared them to those listed for GALLAMP XI.M9 for consistency.
In accordance with NEDP-23, Revision 0, "BWR Reactor Pressure Vessel Internals Inspections (RPVII)," the applicant stated that the staff-approved BWRVIP documents identified in the GALL
 
Report for this AMP are applicable to all units.
The staff identified a difference in the program description, as well as in the program element for preventive action, as discussed below.The GALL AMP XI.M8 recommends that BWR water chemistry control be performed in accordance with BWRVIP-29, which references the 1993 revision of EPRI TR-103515, "BWR
 
Water Chemistry Guidelines." However, the BFN water chemistry programs are based on
 
BWRVIP-79, which references the 2000 revision of EPRI TR-103515-R2 and uses HWC with
 
NMCA to control both the detrimental impurities and crack initiation and growth. In the LRA, the
 
applicant stated that BFN has not applied for any relief for vessel internals component weld
 
inspections in accordance with BWRVIP-62, which allows relief for welds exposed to hydrogen
 
water chemistry. The staff found this difference acceptable, since BWRVIP-79 is the current
 
revision to industry practice.
The staff noted that the applicant will utilize BWRVIP-76 (which supersedes BWRVIP-07 and BWRVIP-63) for core shroud inspection and flaw evaluation guidelines during the extended
 
period of operation.
The applicant stated, as documented in the staff's audit and review report, that BFN committed to the use of BWRVIP documents (transmittal of revised BWRVIP commitment letter to the staff, dated June 2, 1997, RIMS R12 970612 789) and that the commitment to use BWRVIP
 
documents includes evaluating the SER (for BWRVIP documents), and completing the
 
applicable SER action items. The staff found this acceptable since the applicant will use the
 
results of the staff review in implementing BWRVIP-76.
The staff requested a clarification pertaining to the utilization of BWRVIP-44 and BWRVIP-45 as part of the vessel internals AMP.
The applicant also stated that, as documented in the staff's audit and review report, even though BWRVIP-44 and BWRVIP-45 are not specifically mentioned in BWRVIP-94 or NEDP-23 (which implements BWRVIP-94), the applicant previously committed to the use of BWRVIP documents (in revised BWRVIP Commitment Letter to the staff, dated June 2, 1997, RIMS R12
 
970612 789). Should weld repair of nickel-based alloys be needed, the applicant would follow
 
the guidelines of BWRVIP-44 and BWRVIP-45 as stated in NEDP-23. The staff found this
 
acceptable since the applicant is committed to utilization of BWRVIP-44 and BWRVIP-45, if the
 
need arises. The staff found this acceptable, and the commitment is incorporated into SER
 
Appendix A.
The staff noted that the applicant is taking a deviation to BWRVIP-18 on two specific items: i) pertaining to Unit 3 core spray repair design and, ii) BWRVIP- 41 on Unit 3 jet pump #5 repair
 
design. The applicant addressed this issue in its responses dated January 31, 2005, and
 
May 25, 2005, to the staff RAI B.2.1.12, and the details and staff disposition of the issue is
 
shown in SER Section 3.1.2.2.7. The staff, in a follow-up call on March 29, 2005, inquired 3-47 whether the applicant planned to take any exceptions to the implementation of BWRVIP inspection guidelines as a part of the AMP for the reactor vessel internals. If so, the applicant
 
must submit the exceptions (including the exceptions that were taken on BWRVIP-18 and
 
BWRVIP-41) to the staff for review and approval no later than two years prior to the
 
commencement of the extended period of operation. The applicant in its response dated
 
May 25, 2005, confirmed that it currently has not identified any exception to the BWRVIP
 
guidelines. Hence the staff considered this RAI resolved.
Enhancement. In LRA Section B.2.1.12, the applicant identified one enhancement to make thisAMP consistent with GALL AMP XI.M9. The BW RVIP guidelines will be implemented on Unit 1 prior to the period of extended operation. The staff found this enhancement acceptable since it
 
will make the applicant's program consistent for all three units.
Operating Experience. In the LRA, the applicant stated that extensive cracking has been observed in core shrouds at both horizontal and vertical welds (GL 94-03, NRC IN 97-17). It has
 
affected shrouds fabricated from Type 304 and Type 304L SS, which is generally considered to
 
be more resistant to SCC. Weld regions are most susceptible, although it is not clear whether
 
this is due to sensitization and/or impurities associated with the welds, or the high residual
 
stresses in the weld regions. This experience is reviewed in GL 94-03 and NUREG-1544. Some
 
experiences with visual inspections are discu ssed in IN 94-42. Most of the BWR reactors, including BFN, have experienced cracking of RPV internal components.
The staff concluded that implementation of the applicable BWRVIP guidelines provides reasonable assurance that cracking of BWR RPV internal components is being adequately
 
managed, such that there is no loss of intended function.
During the concurred audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing
 
basis. The staff concluded there is reasonable assurance that operating experience will
 
continue to be reviewed in the future to ensure that the effects of aging will be adequately
 
managed.UFSAR Supplement. In LRA Section A.1.12, the applicant provided the UFSAR supplement for the BWR Vessel Internals Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3-48 3.0.3.2.8  Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program Summary of Technical Information in the Application. The applicant's Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) Program is
 
described in LRA Section B.2.1.14, "Thermal Aging and Neutron Irradiation Embrittlement of
 
Cast Austenitic Stainless Steel Program." In the LRA, the applicant stated that this is an existing
 
program. This program is consistent, with enhancement, with GALL AMP XI.M13, "Thermal Aging and Neutron Irradiation Embrittlement of CASS."
The applicant stated that the Thermal Aging and Neutron Irradiation Embrittlement of CASS Program monitors the effects of loss of fracture toughness on the intended function of the
 
component by performing supplemental exami nations of CASS reactor vessel internals components. The reactor vessel internals receive a visual inspection in accordance with the ASME Code Section XI Subsection IWB, Category B-N-3 requirements.
Additional enhanced visual inspections that incorporate the requirements of the BWR Vessel Internals Program are performed to detect the effects of loss of fracture toughness due to
 
thermal aging and neutron irradiation embrittlement of CASS reactor vessel internals.
The enhanced visual inspections include the ability to achieve a 0.0005-inch resolution, with the conditions (e.g., lighting and surface cleanliness) of the inservice examination bounded by those
 
used to demonstrate the resolution of the inspection technique.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancement and its
 
justifications to determine whether the AMP, with enhancement, remains adequate to manage
 
the aging effects for which it is credited.
In the LRA, the applicant stated that the Thermal Aging and Neutron Irradiation Embrittlement ofCASS Program is consistent with the GALL AMP XI.M13, "Thermal Aging and Neutron
 
Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS)." The staff reviewed the
 
program elements (see SER Section 3.0.2.1) contained in the AMP basis document and compared them against GALL AMP XI.M13 for consistency. The staff noted a difference in the
 
program element for the scope of the program, as discussed below.The GALL AMP XI.M13 recommendations state that the scope of the program should specify the guidelines for identification of susceptible components determined to be limiting from the
 
standpoint of thermal aging susceptibility (i.e., ferrite and molybdenum contents, casting
 
process, and operating temperature) and/or neutron irradiation embrittlement (neutron fluence).
 
Either a supplemental examination of the affected component based on the neutron fluence or a
 
component-specific evaluation to determine its susceptibility to loss of fracture toughness is to
 
be performed. The staff noted that the Thermal Aging and Neutron Irradiation Embrittlement of
 
CASS Program does not address this screening process. In response to a question from the
 
staff, the applicant stated that the scope of the Thermal Aging and Neutron Irradiation
 
Embrittlement of CASS Program includes supplem ental examination of all CASS reactor vessel internal components. Since screening is not used, there is no need to define a screening
 
process. The staff found this acceptable.
3-49 The staff determined that all other program elements are consistent with GALL, with one enhancement related to the program element "Scope of Program." The applicant stated in the
 
LRA Appendix B that the enhancement to the Thermal Aging and Neutron Irradiation
 
Embrittlement of CASS AMP will be implement ed on Unit 1. The enhancement is scheduled for implementation prior to the period of extended operation.
Staff Evaluation. In LRA Section B.2.1.14, the applicant identified one enhancement to makethis AMP consistent with GALL AMP XI.M13.
This AMP will be implemented on Unit 1 prior to the period of extended operation. The staff found that with the implementation of this
 
enhancement, BFN will be consistent with the affected program element for all three units.
Operating Experience. In the LRA, the applicant stated that cracking had been detected in the reactor vessel internals at several domestic and overseas boiling water reactors. In June 1994, the BWRVIP was formed to address integrity issues arising from inservice degradation of
 
reactor vessel internals. Since that time, the BWRVIP has published several reports that present
 
guidelines for inspecting, evaluating, and repairing reactor vessel internals.
The staff concluded that implementation of the BWRVIP guidelines for inspecting, evaluating, and repairing reactor vessel internals provides reasonable assurance that loss of fracture
 
toughness of CASS reactor pressure vessel internal components is being adequately managed, such that there is no loss of intended function.In GALL AMP XI.M13, void swelling is also identified as an aging mechanism leading to loss of fracture toughness in CASS reactor vessel internals. The applicant evaluated this program
 
element "operating experience" in section LRA B.2.1.14 on page B-48 and concluded as
 
follows: The continued implementation of the Thermal Aging and Neutron Irradiation Embrittlement of CASS aging management progr am provides reasonable assurance that the aging effects will be managed so that the systems and components within the scope
 
of this program will continue to perform their intended functions consistent with the
 
current licensing basis for the period of extended operation.
The BFN Reactor Vessel Internals Program is based on research data obtained from both laboratory-aged and service-aged materials. EPRI TR-107521 addresses data gathered from
 
liquid-metal-cooled fast breeder reactors, and how it may possibly be related to a PWR
 
component (baffle-former bolt) that is in almost direct contact with the fuel in a PWR. Since a
 
BWR does not have components in a similar location and thus can reasonably be expected to
 
experience less fluence, the staff concludes that is not a concern with BFN. Past studies of void
 
swelling by ANL, ORNL, HEDL, and GE have shown that the threshold fluence for void swelling
 
is approximately 10 22 n/cm 2 , which is well in excess of the fluence experienced by typical boiling water reactor CASS components. Secondly, the EPRI report notes that field experience does
 
not suggest that void swelling is a significant issue. The lowest temperature for which this phenomenon is conjectured to occur is 300 °C (572 °F), which is higher than the temperature
 
experienced by BWR reactor vessel internals. Hence the staff concluded that void swelling is
 
not an aging effect applicable to BFN.
During the onsite audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing basis. The 3-50 staff concluded there is reasonable assurance that operating experience will continue to be reviewed in the future to ensure that the effects of aging will be adequately managed.
UFSAR Supplement. In LRA Section A.1.14, the applicant provided the UFSAR supplement for the Thermal Aging and Neutron Irradiation Embrittlement of CASS Program. The staff reviewed
 
this section and determined that the information in the UFSAR supplement provides an
 
adequate summary description of the program. The staff found this section of the UFSAR
 
supplement met the requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.9  Flow-Accelerated Corrosion Program
 
Summary of Technical Information in the Application. The applicant's Flow-Accelerated Corrosion (FAC) Program is described in LRA Section B.2.1.15, "Flow-Accelerated Corrosion
 
Program." In the LRA, the applicant stated that this is an existing program. This program isconsistent, with the enhancement, with GALL AMP XI.M17, "Flow-Accelerated Corrosion
 
Program."In the LRA, the applicant stated that the FAC Program was developed in response to GL 89-08,"Erosion/Corrosion-Induced Pipe Wall Thinning." The program is based on the guidelines of
 
EPRI NSAC-202L, "Recommendations for an Effe ctive Flow Accelerated Corrosion Program," Revision 2. The FAC Program includes the use of an industry-accepted computer code to
 
predict FAC in carbon steel lines containing high-energy fluids (two-phase as well as
 
single-phase systems subject to FAC). The program includes analysis to determine critical
 
locations, baseline inspections to determine the extent of thinning at these locations, and
 
follow-up inspections to confirm the predictions. Repair, replacements, or re-evaluations are performed as necessary.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancement and its
 
justifications to determine whether the AMP, with enhancement, remains adequate to manage
 
the aging effects for which it is credited.
In the LRA, the applicant stated that the FAC Program will be consistent with GALLAMP XI.M17, "Flow-accelerated Corrosion." The staff reviewed the program elements (see SER
 
Section 3.0.2.1) contained in the AMP basis document and compared them to those listed for GALL AMP XI.M17 for consistency. The staff also conducted a review of implementing 3-51 procedure 0-TI-140 "BFN Technical Instruction, Monitoring Program for Flow-Accelerated Corrosion," Revision 0, 03/15/02.
Enhancement. In LRA Section B.2.1.15, the applicant identified one enhancement to make thisAMP consistent with GALL AMP XI.M17. The NSAC-202L-R2 recommendations will be
 
implemented on Unit 1 prior to the period of extended operation. The staff found this
 
enhancement acceptable since it will make the applicant's program consistent for all three units.
Operating Experience. In the LRA, the applicant stated that wall-thinning problems in single-phase systems had occurred in feedwater and condensate systems (NRC IE Bulletin No.
87-01 and INs 81-28, 92-35, and 95-11), in two-phase piping in extraction steam lines (NRC INs
 
89-53 and 97-84), and in moisture separator and feedwater heater drains (INs 89-53, 91-18, 93-21, and 97-84) throughout the industry.
The applicant's experience with its FAC Program activities has shown that the program can determine susceptible locations for FAC, predict component degradation, and detect
 
wall-thinning in components due to FAC, thus providing for timely evaluation, repair, or
 
replacement prior to loss of intended function. When FAC problems have been identified, corrective actions have been taken to prevent recurrence. For example, extraction steam, heater drain, and heater vent line piping have experienced wall-thinning due to FAC. This piping
 
is being replaced, primarily with FAC-resistant materials.
The staff reviewed several PERs that are included in the basis document, and concluded that implementation of the applicant's program provides reasonable assurance that loss of material
 
due to FAC is being adequately managed, such that there is no loss of intended function.
During the onsite audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing basis. The
 
staff concluded there is reasonable assurance that operating experience will continue to be
 
reviewed in the future to ensure that the effects of aging will be adequately managed, consistent
 
with the GALL Report.
UFSAR Supplement. In LRA Section A.1.14, the applicant provided the UFSAR supplement for the FAC Program. The staff reviewed this section and determined that the information in the
 
UFSAR supplement provides an adequate summary description of the program. The staff found
 
this section of the UFSAR met the requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3-52 3.0.3.2.10  Bolting Integrity Program Summary of Technical Information in the Application. The applicant's Bolting Integrity Program is described in LRA Section B.2.1.16, "Bolting Integrity Program." In the LRA, the applicant
 
stated that this is an existing program. This progr am is consistent, with exceptions, with GALLAMP XI.M18, "Bolting Integrity."
The applicant stated that the Bolting Integrity Program provides for condition monitoring of selected pressure-retaining bolted joints and external surfaces of piping and components within
 
the scope of license renewal. The applicant claimed that the Bolting Integrity Program is
 
consistent with the guidelines of EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear
 
Power Plants," and the additional recommendations of NUREG-1339, "Resolution of Generic
 
Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants," to prevent or mitigate
 
degradation and failure of SR bolting. According to the applicant, the Bolting Integrity Program
 
includes the following AMPs:
* ASME Code Section XI, Subsections IWB, IWC, and IWD Inservice Inspection Program for Class 1, 2, and 3 components. (B.2.1.4)
* Systems Monitoring Program for bolts not included in ASME Code Section XI, Inservice Inspection Program. (B.2.1.39)The applicant stated that the Bolting Integrity Program is consistent with GALL XI.M18 with the following exceptions:
Exception 1. The GALL Report indicates that the program covers all bolting within the scope of license renewal including structural bolting. The applicant stated that the
 
Structures Monitoring Program covers aging management of structural bolting.
Exception 2. The GALL Report indicates that the program covers all bolting within the scope of license renewal including bolting for Class 1 nuclear steam supply system (NSSS) component supports. The applicant stated that the ASME Code Section XI, Subsection IWF Program, covers aging management of Class 1 NSSS component
 
support bolts at the BFN Units.
These two exceptions affect the program element s "Scope of Program " and "Detection of Aging Effects." The applicant evaluated the exceptions in LRA Appendix B and stated that structural bolting is addressed by the Structures Monitoring Program and the ASME Section XI, Subsection IWF Program. These two AMPs are considered appropriate for managing the aging
 
of these types of bolting.
The applicant also stated that requirements that are specified in EPRI NP-5769, with the exceptions noted in NUREG-1339, will be applicable for all SR bolting at the BFN units. The
 
applicant indicated in the LRA that EPRI TR-104213, "Bolted Joint Maintenance and
 
Applications Guide," is used as a basis for evaluation of the structural integrity of NSR bolting.
The inspection requirements that are specified in ASME Code Section XI, Subsections IWB, IWC, IWD, and EPRI NP-5769 will be used in detecting the aging effects of all SR ASME
 
Class 1, 2, and 3 bolting, and NSSS component-support bolting. The applicant indicated that
 
these requirements are consistent with the GALL Report.
3-53 In evaluating AMP B.2.1.16, the applicant stated that continued implementation of the Bolting Integrity Program provides reasonable assurance that the aging effects will be managed so that
 
the systems and components within the scope of th is program will continue to perform their intended functions consistent with the CLB for the period of extended operation.
This AMP is credited for managing degradation of bolting in the RCS, engineered safety feature (ESF), auxiliary, and steam and power conversion systems.
Staff Evaluation. During review, the staff confirmed the applicant's claim of consistency with the GALL Report. Furthermore, the staff reviewed the exceptions and their justifications to
 
determine whether the AMP, with exceptions, remains adequate to manage the aging effects for
 
which it is credited.
For SR bolting, the GALL Report relies on staff recommendations and guidelines for a comprehensive Bolting Integrity Program delineated in NUREG-1339 "Resolution of Generic
 
Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants," and industry's
 
technical basis for the program and guidelines in regard to material selection and testing, bolting
 
preload control, ISI, plant operation and maintenance, and evaluation of structural integrity of
 
bolted joints outlined in EPRI NP-5769, with the exceptions noted in NUREG-1339. These requirements are consistent with NUREG 1801 Section XI.M18, and staff found them
 
acceptable. Since there are no high-strength low-alloy steel bolts (yield strength greater than
 
150 ksi) at the BFN units, aging effects due to SCC is not credible and can be excluded from
 
the AMP. With regard to NSR bolting, the applicant stated that it will comply with the aging management attributes delineated in EPRI TR-104213 including material procurement, use of approved
 
lubricants and sealants, proper torquing, and leakage evaluations. The staff found the
 
applicant's Bolting Integrity Program for NSR bolting consistent with the recommendations in the
 
GALL and the standards delineated in EPRI TR-104213.
The LRA states that the Bolting Integrity Program does not include bolting for Class 1 NSSS component-support bolts. The applicant stated that there are no high-strength bolts (yield
 
strength greater than 150 ksi) in NSSS component supports. The staff evaluated this attribute
 
and found it acceptable.
The staff previously accepted the use of periodic ISI of closure bolting as an acceptable AMP for loss of mechanical closure integrity, since failure of the mechanical joint, as evidenced by
 
leakage, can be attributed to loss of material, cracking of bolting materials, or loss of preload.
The staff determined that periodic ASME Code Section XI ISI and plant preventive maintenance
 
programs as described in NUREG-1339 and EPRI NP-5769 can be effectively relied upon to
 
identify loss of closure integrity for bolted assemblies. Therefore, the applicant's management of
 
loss of mechanical closure integrity is adequate for managing the aging effects of loss of
 
material, cracking, and loss of preload. The staff determined that the applicant demonstrated its compliance with all the attributes of GALL AMP XI.M18 for bolting in the RCS with exceptions.
 
The staff reviewed these exceptions, and concluded that they do not have any technical impact on the effectiveness of managing the aforementioned aging effects of the bolts in the RCS.
 
Therefore, the staff concluded that by implementing the Bolting Integrity Program, which is
 
consistent with GALL, the aging effects of the bolting in the RCS will be effectively managed in a
 
timely manner for the period of extended operation.
3-54 The staff's review of the applicant's program for managing the effects of aging on structural bolting and bolting in Class 1 NSSS component supports is provided in the discussion in the SER regarding ASME Code Section XI Subsection IWF Program and Structures Monitoring
 
Program respectively.
Operating Experience. In evaluating the program element, the applicant stated in LRA Appendix B that the BWR fleet of plants, including BFN, has experienced bolting degradation
 
issues. The industry and BFN has implemented a Bolting Integrity Program, which adequately
 
detected bolting integrity issues (degradation of bolting material). The Bolting Integrity Program
 
has been effective at detecting degradation of bolting and corrective actions have been taken
 
prior to the loss of its intended function. BFN uses no high strength bolts (actual yield strength
 
>150 ksi).
UFSAR Supplement. In LRA Section A.1.15, the applicant provided the UFSAR supplement for the Bolting Integrity Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the exceptions and the
 
associated justifications and determined that the AMP, with exceptions, is adequate to manage
 
the aging effects for which it is credited. The staff concluded that the applicant had
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP
 
and concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.2.11  Open-Cycle Cooling Water System Program
 
Summary of Technical Information in the Application. The applicant's Open-Cycle Cooling Water (OCCW) System Program is described in LRA Section B.2.1.17, "Open-Cycle Cooling Water System Program." In the LRA, the applicant stated that this is an existing program. This program is consistent, with enhancement, with GALL AMP XI.M20, "Open-Cycle Cooling Water System."The OCCW System Program relies on implementat ion of the recommendations of GL 89-13 to ensure that the effects of aging on the OCCW system will be managed for the extended period of operation. The program includes surveillance and control techniques to manage aging effects
 
caused by biofouling, corrosion, erosion, protective coating failures, and silting in the OCCW
 
system or structures and component s serviced by the OCCW system.
Implementation of GL 89-13 activities provides for management of aging effects due to loss of material, fouling due to micro- or macro-organisms, and heat transfer aging effects in raw water
 
cooling water systems. The applicant does not utilize protective coatings in any raw water
 
systems, as addressed in IN 85-24. Therefore, protective coating failures do not apply to BFN.
3-55 Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancement and its
 
justifications to determine whether the AMP, with the enhancement, remains adequate to
 
manage the aging effects for which it is credited.
The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the OCCW System Program and associated bases document s, and compared them to those listed forGALL AMP XI.M20 report for consistency. The staff also reviewed selected implementing
 
procedures, including Standard Program and Process (SPP)-9.7, "Corrosion Control Program,"
 
Rev. 6, which establishes the engineering requirements, details, and strategies to control
 
corrosion of plant systems, components, equipment and structures, and the responsibilities and
 
methodologies utilized to identify, monitor, trend, and control corrosion.
Based on its review, the staff found that the program elements of the OCCW System Programare consistent with GALL AMP XI.M20.
Enhancement. In LRA Section B.2.1.17, the applicant identified one enhancement to make thisAMP consistent with GALL AMP XI.M20. GL 89-13 will be implemented on Unit 1 prior to the
 
period of extended operation. The staff found this enhancement acceptable since it will make
 
the applicant's program consistent for all three units.
Operating Experience. In LRA Section B.2.1.17, the applicant stated that it has been implementing the guidance of GL 89-13 for approximately 10 years, and found the guidance to
 
be effective in managing aging effects due to biofouling, corrosion, erosion, pitting, and silting in
 
structures and components se rviced by OCCW systems.
The raw water fouling and corrosion control program inspection and testing activities have detected and evaluated the presence of biofouling, corrosion, microbiologically influenced
 
corrosion (MIC), and silting. The system and co mponent corrective actions were implemented prior to loss of system function. The raw water fouling and corrosion control program activities
 
adequately manage the aging effects of loss of material, cracking, pitting, flow blockage, and
 
reduction of heat transfer in components exposed to raw cooling water.
The staff concluded that implementation of the applicant's program provides reasonable assurance that aging effects due to biofouling, corrosion, erosion, pitting, and silting in
 
structures and components serviced by O CCW systems are being adequately managed, such that there is no loss of intended function.
During the onsite audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing basis. The
 
staff concluded there is reasonable assurance that operating experience will continue to be
 
reviewed in the future to ensure that the effects of aging will be adequately managed, consistent with the guidance in the GALL Report.
UFSAR Supplement. In LRA Section A.1.16, the applicant provided the UFSAR supplement for the OCCW System Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the 3-56 program. The staff found this section of the UFSAR supplement met the requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.12  Closed-Cycle Cooling Water System Program
 
Summary of Technical Information in the Application. The applicant's Closed-Cycle Cooling Water (CCCW) System Program is described in LRA Section B.2.1.18, "Closed-Cycle Cooling Water System Program." In the LRA, the applicant stated that this is an existing program. This program is consistent, with an enhancement, with GALL AMP XI.M21, "Closed-Cycle Cooling Water System."
The CCCW System Program includes preventiv e measures to minimize corrosion and surveillance testing and inspection to monitor the effects of corrosion on the intended function of
 
the component. The program relies on maintenance of system corrosion inhibitor concentrations
 
within specified limits of EPRI TR-107396, "Closed Cooling Water Chemistry Guideline," to
 
minimize corrosion. Surveillance testing and inspection in accordance with standards in EPRI
 
TR-107396 for CCCW systems is performed to evaluate system and component performance.
These measures will ensure that the CCCW system and components serviced by the CCCW system are performing their functions acceptably.
CCCW System Program will be enhanced to implem ent EPRI TR-107396 for Unit 1 prior to the period of extended operation.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancement and its
 
justifications to determine whether the AMP, with the enhancement, remains adequate to
 
manage the aging effects for which it is credited.
The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the CCCW System Program and associated bases document s, and compared them to those listed forGALL AMP XI.M21 for consistency.
The staff also reviewed the applicant's implementing procedures, including Browns Ferry Chemical Instruction CI-13.1, and "Browns Ferry Nuclear Plant Chemistry Program," Revision 17, which incorporates EPRI TR-107396, "Closed Cooling Water Chemistry Guidelines."
 
Appendix A of that procedure provides water quality control specifications for the reactor
 
building closed-cooling water system, drywell outage chiller (when inservice), off-gas chiller 3-57 systems, closed-building heating, generator stator cooling water, diesel generator cooling water, and control bay chiller systems. The parameter m onitored, monitoring frequency, administrative goal, and action levels for corrective actions are identified for each system.
The staff's review determined that the applicant's CCCW systems program monitors the effects of corrosion by system chemistry sampling, c hemical treatment and water chemistry trending in accordance with the Water Chemistry Program. The chemistry parameters are monitored and maintained in accordance with the BFN chemistry specifications and recommendations of EPRI
 
TR-107396. The parameters monitored include nitrate, pH, conductivity, tolyltriazole, bacteria (aerobic and SRBs ), sulfates, metals (iron, copper), ammonia, chloride, calcium, molybate, and
 
glycol (weight percent). If parameter limits are exceeded, the chemistry control procedures
 
require corrective action to be taken to restore parameters to within the acceptable range.
 
Maintenance of water chemistry and corrosion inhibitor levels within the chemistry parameters
 
mitigate loss of material, cracking, and reduction of heat transfer. In addition, regular scheduled
 
system flow balances, pump suction and di scharge pressure, heat exchanger flows, and temperatures and maintenance inspections are performed on system/components to detect, monitor, control, and minimize corrosion aging effects. The system heat exchangers are also
 
cleaned and inspected to detect, monitor, control, and minimize corrosion aging effects that
 
could cause a reduction of heat transfer.
Based on its review, the staff found that the program elements of the CCCW System Programare consistent with GALL AMP XI.M21.
Enhancement. In LRA Section B.2.1.18, the applicant identified one enhancement to make thisAMP consistent with GALL AMP XI.M21. EPR I TR-107396 will be implemented on Unit 1 prior to the period of extended operation. The staff found this enhancement acceptable since it will
 
make the applicant's program consistent for all three units.
Operating Experience. In the LRA, the applicant stated that industry operating experience demonstrates that the use of corrosion inhibitors in closed-cooling water systems that are
 
monitored and maintained by chemistry activities is effective in mitigating loss of material, cracking, and reduction of heat transfer. The BFN CCCW systems have not experienced a loss
 
of intended function of components due to corrosion product buildup or through-wall cracking of
 
components. The CCCW systems inspection and testing have detected loss of material and
 
corrosion product buildup. These aging effects were identified and corrected prior to loss of
 
system functions.
The staff concluded that implementation of the applicant's program provides reasonable assurance that loss of material, cracking, and reduction of heat transfer in CCCW systems are
 
being adequately managed such that there is no loss of intended function.
During the onsite audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing basis. The
 
staff concluded there is reasonable assurance that operating experience will continue to be
 
reviewed in the future to ensure that the effects of aging will be adequately managed, consistent
 
with the guidance in the GALL Report.
UFSAR Supplement. In LRA Section A.1.17, the applicant provided the UFSAR supplement for the CCCW System Program. The staff reviewed this section and determined that the 3-58 information in the UFSAR supplement provides an adequate summary description of the program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.13  Inspection of Overhead Heavy Load and Light Load Handling Systems Program
 
Summary of Technical Information in the Application. The applicant's Inspection of the Overhead Heavy Load and Light Load Handling Sy stems Program is described in LRA Section B.2.1.20, "Inspection of Overhead Heavy Load and Light Load Handling Systems
 
Program." In the LRA, the applicant stated that this is an existing program. This program isconsistent, with an exception, with GALL AMP XI.M23, "Inspection of Overhead Heavy Load (Related to Refueling) and Light Load Handling Systems."
In LRA Section B.2.1.20, the applicant stated that Inspection of the Overhead Heavy Load and Light Load Handling Systems Program includes crane inspection activities to verify the
 
structural integrity of the crane components required to maintain the crane intended function.
 
Visual inspections assess conditions such as loss of material due to corrosion of structural
 
members, misalignment, flaking, side wear of rails, loose tie-down bolts, and excessive wear or
 
deformation of monorails. Crane functional tests are periodically performed to assure the cranes
 
capability. The effectiveness of the program is monitored in accordance with the guidance of RG
 
1.160, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the exception and its justifications
 
to determine whether the AMP, with the exception, remains adequate to manage the aging
 
effects for which it is credited.
The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the Inspection of the Overhead Heavy Load and Light Load Handling Systems Program and associated bases documents, and compared them to those listed for GALL AMP XI.M23 for consistency.In LRA Section B.2.1.20, the applicant identified an exception to GALL AMP XI.M23 that affects GALL Report element Parameters Monitored/Inspected. Reactor building crane fatigue was
 
evaluated as a TLAA in LRA Section 4.7.1. The disposition of the TLAA is that the analyses are
 
valid through the period of extended operation because the 60-year 7,500-cycle estimate
 
remains a small fraction of the 100,000 cycle design. Therefore, the applicant stated that aging
 
management of crane fatigue is not required.
3-59 Exception. The staff evaluation of the affected GALL Report program element, "Parameters Monitored/Inspected" (Element 3), for the acceptability of the exception is as follows:
Parameters Monitored/Inspected. The program evaluates the effectiveness of the maintenance monitoring program and the effects of past and future usage on the
 
structural reliability of cranes. The number and magnitude of lifts made by the crane are
 
also reviewed.
The staff found this exception acceptable on the basis that the crane is designed for 100,000 lift-cycles, compared to the applicant's 60-year estimate of 7,500 cycles (1.5 times 40-year estimate of 5,000 cycles), as documented in LRA Section 4.7.1. The staff found that, with
 
evaluation of the exception discussed below, t he program elements reviewed for the Inspection of the Overhead Heavy Load and Light Load Handling Systems Program are consistent with GALL AMP XI.M23.
Operating Experience. In the Inspection of the Overhead Heavy Load and Light Load Handling Systems Program basis document, the applicant stated that no incidents of failure of passive
 
crane and hoist components due to aging have occurr ed at Browns Ferry. The requirements for monitoring the effectiveness of maintenance at nuclear power plants provided in 10 CFR 50.65
 
have been incorporated into the Maintenance Rule Program procedures.
The staff concluded that the crane inspection program activities, implemented as part of the Maintenance Rule Program, provide reasonable assurance that the intended functions of crane
 
and hoist passive components will be maintained during the period of extended operation.
During the onsite audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing basis. The
 
staff concluded there is reasonable assurance that operating experience will continue to be
 
reviewed in the future to ensure that the effects of aging will be adequately managed, consistent
 
with the guidance in the GALL Report.
UFSAR Supplement. In LRA Section A.1.18, the applicant provided the UFSAR supplement for the Inspection of Overhead Heavy Load and Light Load Handling Systems Program. The staff
 
reviewed this section and determined that the information in the UFSAR supplement provides
 
an adequate summary description of the program. The staff found this section of the UFSAR
 
supplement met the requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the exception and the
 
associated justifications and determined that the AMP, with the exception, is adequate to
 
manage the aging effects for which it is credited. The staff concluded that the applicant had
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP
 
and concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3-60 3.0.3.2.14  Compressed Air Monitoring Program Summary of Technical Information in the Application. The applicant's Compressed Air Monitoring Program is described in LRA Section B.2.1.21, "Compressed Air Monitoring
 
Program." In the LRA, the applicant stated that this is an existing program. This program isconsistent, with enhancements, with GALL AMP XI.M24, "Compressed Air Monitoring."
The Compressed Air Monitoring Program will be enhanced prior to the period of extended operation to include program and procedure upgrades that will be credited for license renewal, to ensure that the applicable aging effects are discovered and evaluated. Also, the Unit 1
 
control air system procedures will be updated to fully implement the compressed air monitoring program on Unit 1, prior to Unit 1 re-start from its current extended outage.
The Compressed Air Monitoring Program consis ts of condition monitoring (inspection and testing of the system) and preventive actions (air quality at various locations in the system is monitored to ensure that oil, water, rust, dirt, and other contaminants are kept within specified
 
limits). The program includes inspection, monitori ng, and testing of the entire system, including frequent leak testing of valves, piping, and ot her system components, especially those made of carbon steel, and preventive monitoring that checks air quality at various locations in the system
 
to ensure that oil, water, rust, dirt, and other contaminants are kept within the specified limits.
The Compressed Air Monitoring Program is based on GL 88-14, "Instrument Air Supply System Problems Affecting Safety-Related Equipment," and the Institute of Nuclear Power Operations (INPO) Significant Operating Experience Report (SOER) 88-01, "Instrument Air System
 
Failures." The AMP also incorporates provisions conforming to the guidance of the EPRI
 
NP-7079, issued in 1990 to assist utilities in identifying and correcting system problems in the
 
instrument air system and to enable them to maintain required industry safety standards.
 
Additionally, the Compressed Air Monitoring Program will be upgraded to implement these guidelines of EPRI TR-108147, which addresses maintenance of the latest compressors and
 
other instrument air system equipment in use, and the ASME Code operations and maintenance
 
standards and guides (ASME Code OM-S/G-1998, Part 17), which provide additional guidance
 
for the maintenance of the instrument air system, including recommended test methods, test
 
intervals, parameters to be measured and evaluat ed, acceptance criteria, corrective actions, and records requirements.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancements and their
 
justifications to determine whether the AMP, with the enhancements, remains adequate to
 
manage the aging effects for which it is credited.
In LRA Section B.2.1.21, the applicant indicated that the Compressed Air Monitoring Program requires implementation of two enhancements to achieve consistency with GALL AMP XI.M24 for all three units.
Enhancement 1. The staff evaluation of the affected GALL Report program elements,"Preventive Actions" (Element 2) and "Detecti on of Aging Effects" (Element 3), for the acceptability of the enhancement is as follows:
3-61 Preventive Actions
- The system air quality is monitored and maintained in accordance with the plant owner's testing and inspection plans, which are designed to ensure that
 
the system and equipment meet specified operability requirements. These requirements are prepared from consideration of manufacturer's recommendations for individual
 
components and guidelines based on ASME Code OM-S/G-1998, Part 17;
 
ISA-S7.0.01-1996; EPRI NP-7079; and EPRI TR-108147. The preventive maintenance
 
program addresses various aspects of the inoperability of air-operated components due
 
to corrosion and the presence of oil, water, rust, and other contaminants.
Detection of Aging Effects
- Guidelines in EPRI NP-7079, EPRI TR-108147, and ASME Code OM-S/G-1998, Part 17, ensure timely detection of degradation of the compressed
 
air system function. Degradation of the piping and any equipment would become evident by observation of excessive corrosion, by the discovery of unacceptable leakage rates, and by failure of the system or any item of equipment to meet specified performance limits.Enhancement 2. Unit 1 control air system procedures will be updated to fully implement the Compressed Air Monitoring Program on Unit 1. This enhancement is scheduled for completion
 
prior to Unit 1 re-start from its current extended outage.
For all units, the Compressed Air Monitoring Program will be upgraded to implement the following guidelines: ASME Code OM-S/G-2000, Pa rt 17, "Performance Testing of Instrument Air Systems in Light-Water Reactor Power Plants"; ANSI/ISA-S7.0.01-1996, "Quality Standard
 
for Instrument Air"; and EPRI TR-108147, "Compr essor and Instrument Air System Maintenance Guide." This enhancement is scheduled for completion prior to the start of the period of
 
extended operation.
The staff concurred that with the implementation of these enhancements the Compressed AirMonitoring Program will be consistent with GALL AMP XI.M24 for all three units.
Operating Experience. In LRA Section B.2.1.21, the applicant stated that, through air quality testing and sampling of the compressed air systems, various contaminants such as moisture, oil, and particulates, have been identified above acceptable levels, as documented in the staff's
 
BFN audit and review report. Appropriate corrective actions have been taken.
Potentially significant SR problems pertain ing to air systems have been documented in IN 81-38, IN 87-28, IN 87-28 S1 and licensee event report (LER) 50-237/94-005-3. As a result of
 
GL 88-14 and consideration of INPO SOER 88-01, EPRI NP-7079, and EPRI TR-108147, performance of air systems has improved significantly.
The applicant stated that GL 88-14, IN 81-38, IN 87-28, IN 87-28 S1, INPO SOER 88-01 and EPRI NP-7079 had been adequately addressed and that the control air system performance
 
has improved significantly as a result of GL 88-14, and consideration of INPO SOER 88-01 and EPRI NP-7079. In addition, the control air leak detection program has been effective in
 
detecting leaks and implementing repairs prior to loss of system function. The air quality
 
sampling program effectively monitors the system for moisture, oil, and particulates. This
 
ensures timely repairs prior to degradation to the point of loss of intended function.
3-62 The applicant also identified that the drywell control air system has a trend of moisture problems, which has required considerable attention. To address the current operating
 
deficiencies identified in the drywell control air system, the applicant plans to convert the drywell
 
control air to nitrogen supply on all three units. This conversion has already been initiated for
 
Unit 1. The staff noted that this plant modification addresses a current operating problem, and is
 
not related to any license renewal commitment.
The staff concluded that implementation of the applicant's program provides reasonable assurance that age-related degradation of compressed air systems is being adequately
 
managed, such that there is no loss of intended function.
During the onsite audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing basis. The
 
staff concluded there is reasonable assurance that operating experience will continue to be
 
reviewed in the future to ensure that the effects of aging will be adequately managed, consistent
 
with the guidance in the GALL Report.
UFSAR Supplement. In LRA Section A.1.19, the applicant provided the UFSAR supplement for the Compressed Air Monitoring Program. The staff reviewed this section and determined that
 
the information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.15  BWR Reactor Water Cleanup System Program
 
Summary of Technical Information in the Application. The applicant's BWR Reactor Water Cleanup System Program is described in LRA Section B.2.1.22, "BWR Reactor Water Cleanup
 
System Program." In the LRA, the applicant stated that this is an existing program. Thisprogram is consistent, with an enhancement, with GALL AMP XI.M25, "BWR Reactor Water
 
Cleanup System Program." This program will be enhanced to implement the BWRVIP guidelines, GL 88-01, and GL 89-10 for Unit 1 prior to the period of extended operation.
The BWR Reactor Water Cleanup System Program includes inservice inspection and monitoring for reactor water cleanup (RWCU) system piping welds outboard of the second
 
isolation valve and monitors and controls reac tor water chemistry based on industry-recognized guidelines of EPRI Report TR-103515, "BWR Water Chemistry Guidelines (BWRVIP-79),"
prevents, minimizes, mitigates, and reduces the susceptibility of RWCU system piping to SCC
 
and IGSCC.
3-63 On Units 2 and 3, RWCU system piping has been replaced with piping that is resistant to IGSCC in response to GL 88-01, "NRC Position on Intergranular Stress Corrosion Cracking (IGSCC) in BWR Austenitic Stainless Steel Piping," concerns. In addition, all actions requested
 
in GL 89-10, "Safety-Related Motor-Operated Valve Testing and Surveillance," have been
 
completed.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancement and its
 
justifications to determine whether the AMP, with the enhancement, remains adequate to
 
manage the aging effects for which it is credited.
The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the BWR Reactor Water Cleanup System Program and associated bases documents, and comparedthem to those listed for GALL AMP XI.M25 for consistency.
The staff also reviewed selected implementing procedures, including CI-13.1, "Chemistry Program." This instruction details specific requirements for the chemistry program. This chemical instruction establishes how the chemistry program is implemented and provides specifications to maximize long-term plant availability, minimize environmental impact, and minimize worker radiation exposure. Controlling water quality through control of ingress and
 
cleanup system optimization limits corrosion, minimizes radioactive inventory, and minimizes
 
radioactive releases to the environment. The requirements of this instruction apply to all aspects
 
of the chemistry program associated with BFN and supporting facilities. This instruction defines
 
the minimum requirements for the site and corporate chemistry programs as they apply to BFN.
 
This includes incorporation of EPRI TR-103515, Revision 2 guidelines. In addition, HWC must
 
be installed for mitigation of IGSCC, which will include the RWCU system for Unit 1.
The staff found that the program elements reviewed for BWR Reactor Water Cleanup SystemProgram are consistent with GALL AMP XI.M25.
Enhancement. In LRA Section B.2.1.22, the applicant identified one enhancement tomake this AMP consistent with GALL AMP XI.M25. On Unit 1 the recommendations of
 
GL 88-01 and NUREG-0313 will be implemented and the actions requested in GL 89-10
 
will be satisfactorily completed. These enhancements are scheduled for completion prior
 
to the period of extended operation.
The staff found that with the implementation of this enhancement the BWR Reactor Water Cleanup System Program will be consistent with GALL AMP XI.M25 for all three BFN units.
Operating Experience. In LRA Section B.2.1.22, the applicant stated that IGSCC has occurred in boiling water reactor piping made of austenitic stainless steel. The comprehensive program
 
outlined in GL 88-01 and NUREG-0313 addresses improvements in managing the elements (susceptible material, significant tensile stress, and an aggressive environment) that cause SCC
 
or IGSCC, and has been effective in managing IGSCC in austenitic stainless steel piping in the
 
RWCU system.
The applicant identified that the applicant experienced IGSCC in the past with piping made of austenitic stainless steel. The following meas ures that have been implemented have proven 3-64 effective at managing IGSCC in austenitic stainless steel piping in the RWCU system: (1) replacement of IGSCC-susceptible material with IGSCC-resistant material, (2) establishment of
 
a HWC program, and (3) water chemistry controls in accordance with EPRI guidelines.
The staff concluded that implementation of the recommendations of GL 88-01 and NUREG-0313 and the actions requested in GL 89-10 provides reasonable assurance that
 
cracking of austenitic stainless steel piping in the RWCU system is being adequately managed, such that there is no loss of intended function.
During the onsite audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing basis. The
 
staff concluded there is reasonable assurance that operating experience will continue to be
 
reviewed in the future to ensure that the effects of aging will be adequately managed, consistent
 
with the guidance in the GALL Report.
UFSAR Supplement. In LRA Section A.1.20, the applicant provided the UFSAR supplement for the BWR Reactor Water Cleanup System Program. The staff reviewed this section and
 
determined that the information in the UFSAR supplement provides an adequate summary
 
description of the program. The staff found this section of the UFSAR supplement met the
 
requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.16  Fire Protection Program
 
Summary of Technical Information in the Application. The applicant's Fire Protection Program is described in LRA Section B.2.1.23, "Fire Protection Program." In the LRA, the applicant stated
 
that this is an existing program. This program is consistent, with exceptions and enhancement,with GALL AMP XI.M26, "Fire Protection Program."
The applicant stated in the LRA that the Fire Protection Program manages the aging effects of loss of material, cracking, and change of material properties for plant fire protection features
 
and components. The program manages these aging effects through the use of periodic
 
inspections and tests. The Fire Protection Program includes fire barrier inspections and
 
diesel-driven fire pump tests. Fire protection inspections and tests are mandated by the Fire
 
Protection Report (FPR) Volume 1, which is incorporated by reference into UFSAR 10.11. The
 
FPR requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection of fire-rated doors to ensure that their
 
operability is maintained. The FPR requires that the diesel-driven fire pump be periodically 3-65 tested to ensure that the fuel supply line can perform the intended function. The FPR also includes periodic inspection and test of the carbon dioxide fire suppression system.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in its
 
BFN audit and review report. Furthermore, the staff reviewed the exceptions and enhancement
 
and their justifications to determine whether the AMP, with the exceptions and enhancement, remains adequate to manage the aging effects for which it is credited.
Exception 1. Personnel performing fire seal and fire door inspections are not qualified to VT-1 and VT-3 requirements.
The staff's review of LRA Section B.2.1.23 identified an area in which additional information was necessary to complete the review of the applicant's program elements. The applicant responded
 
to the staff's RAI as discussed below.
In RAI B.2.0.2, dated August 23, 2004, the staff questioned the exception to the GALL Report regarding the qualifications of the personnel performing the inspections of fire barriers, penetration seals, and fire doors who are not qualified to VT-1 and VT-3 requirements. In the
 
LRA the applicant had stated that the personnel performing these inspections are trained and
 
experienced in the fire protection requirements and that the quality of the inspections is
 
equivalent to VT-1 and VT-3 inspections. FPR Section 9.4.11.G discussed semi-annual
 
inspection of fire doors including a check of closers and latching mechanisms. The staff also
 
requested justifications for specific exceptions taken to the GALL Report AMP on fire doors. The
 
GALL Report recommends verification of door clearances to assure the door can perform in a
 
fire and remain latched. The staff further requested additional information concerning how a
 
visual inspection can verify proper closure of latching mechanism and asked the applicant to
 
confirm that the frequency of this surveillance is consistent with the FPR.
Fire Protection Report Volume1 Fire Protecti on Systems Surveillance Requirement 9.4.11.D, CO 2 systems, mandates the CO 2 systems' requirements for demonstrating operability. This test stipulates that the system, including associ ated ventilation system fire dampers and fire door release mechanisms, actuates manually and automatically upon receipt of a simulated actuation
 
signal, and verify flow from each nozzle through a puff test.
In its response, by letter September 30, 2004, the applicant stated:
Surveillance Instruction (SI) 0-SI-4.11.G.2, Semiannual Fire Door Inspection is discussed in the AMP and is being credited as one of the BFN site specific procedures
 
credited for the Fire Protection Aging Management Program. A SI verifies the required
 
clearances are maintained and periodic functional tests of closing mechanisms are
 
performed. The only exception to the GALL in the AMP for fire doors is that inspectors
 
are not qualified to visual examination (VT-1 and VT-3) requirements.
The frequency and inspection of the fire doors is defined in the FPR and the SIs written to satisfy the requirement.
The staff reviewed the SI, acceptance criteria, including surveillance requirement 9.4.11.D, above, and plant operating experience, and concurred the program is adequate for managing 3-66 the effect of aging in the fire doors. Therefore, the staff's concern discussed in RAI B.2.0.2 is resolved.
Exception 2. The FPR requires testing and inspection of the CO 2 system once every 18 months.
LRA Section B.2.1.23, Element 3 - "Parameters Monitored or Inspected" and Element 4 -
"Detection of Aging Effects," takes exceptions over the inspection interval to test for the
 
halon/carbon dioxide fire suppression system every 18 months, instead of biannually as recommended by the GALL Report.
The applicant stated that the 18-month frequency is considered sufficient to ensure system availability and operability based on the plant operating history, and that there has been no
 
aging-related event that has adversely affe cted system operation. The 18-month frequency is included in the CLB.
The staff reviewed the applicant's FPR basis document, plant operating experience, and fire surveillance procedures. Because these aging effects occur over a considerable period of time, the staff concluded that the 18-month inspection interval will be sufficient to detect aging of CO 2.Enhancement 1. The FPR and procedures will be updated to include Unit 1 as an operating rather than a shutdown unit. The Fire Protecti on Program will be fully implemented on Unit 1.
The enhancement is scheduled for completion prior to the period of extended operation In the LRA, the applicant stated that "with the implementation of this enhancement, BFN will be consistent with the affected program element for all three units."
Operating Experience. The applicant reported that operating experience indicates a trend of piping degradation, such as leaks, general corrosion, and biofouling. Piping is replaced as
 
required in response to findings of the inspection and testing activities which indicate the need
 
for corrective actions.
UFSAR Supplement. In LRA Section A.1.21, the applicant provided the UFSAR supplement for the Fire Protection Inspection program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review, RAI response, and audit of the applicant's program, the staff found that those program elements for which the applicant claimed consistency with the
 
GALL program are consistent with the GALL program. In addition, the staff reviewed the
 
exceptions and the associated justifications and determined that the AMP, with exceptions, is
 
adequate to manage the aging effects for which it is credited. Also, the staff has reviewed the
 
enhancement and confirmed that the implementati on of the enhancement prior to the period of extended operation and restart of Unit 1 would result in the existing AMP being consistent with
 
the GALL Report AMP to which it was compared. The staff found that the applicant had
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 3-67 and finds that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.17  Fire Water System Program
 
Summary of Technical Information in the Application. The applicant's Fire Water System Program is described in LRA Section B2.1.24, "Fire Water System Program." In the LRA, the
 
applicant stated that this is an existing program.
This program is consistent, with the exceptionand enhancements, with GALL AMP XI.M27, "Fire Water System," as modified by ISG-04.
The Fire Water System Program applies to water-based fire protection systems that consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes, water storage tanks, and aboveground and underground piping and components that are tested in accordance with
 
the applicable National Fire Protection Association (NFPA) codes and standards. The testing
 
assures the minimum functionality of the systems. The fire water system tests are mandated by
 
the FPR Volume 1, which is incorporated by reference into UFSAR 10.11. The Fire Water
 
System Program is an existing program that takes exceptions to GALL AMP XI.M27 evaluation elements, as modified by ISG-04, and requires enhancements to be consistent with other GALL AMP XI.M27 evaluation elements.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in its
 
BFN audit and review report. Furthermore, the staff reviewed the exception and enhancements
 
and their justifications to determine whether the AMP, with the exception and enhancements, remains adequate to manage the aging effects for which it is credited.
Exception. The applicant takes exception that water-based fire protection systems meet the inspection, testing and maintenance requirements of current NFPA standards.
 
However, the Fire Water Program was developed using NFPA as well as other
 
applicable industry guides and standards and the design of the water-based system
 
generally meets the applicable NFPA standards. This exception affects the program
 
elements, "Parameters Monitored or Ins pected" (Element 3), "Monitoring and Trending"(Element 5), and "Operating Experience" (Element 10) which are discussed below.
Parameters Monitored or Inspected and Monitoring and Trending (As modified by ISG-04) - The GALL Report for this program element specifies that loss of material due to corrosion and biofouling could reduce wall thickness of the fire
 
protection piping system and result in sy stem failure. Therefore, the parameters monitored are the system's ability to maintain pressure and internal system
 
corrosion conditions. The GALL Report recommends that the applicant perform
 
periodic flow testing of the fire water system using the guidelines of NFPA 25, "Standard for the Inspection, Testing, and Maintenance of Water-Based Fire
 
Protection System" Chapter 13, Annexes A & D at the maximum design flow or
 
perform wall-thickness evaluations to ensure that the system maintains its
 
intended function. In evaluating the program elements, the applicant did not
 
confirm that periodic flow testing is performed using the guidelines of NFPA 25
 
as described in the parameters monito red or inspected program element, nor monitor the results of system performance testing and trending, as specified by
 
the current NFPA codes and standards and described in the monitoring and 3-68 trending program element. However, the Fire Water System Program was developed using NFPA as well as other applicable industry guides and
 
standards.
The applicant did not confirm that the water-based fire protection systems are inspected, tested and maintained in accordance with current NFPA standards. Neither has the
 
applicant confirmed that the periodic water flow testing meets the requirements of NFPA
: 25. The staff reviewed SI 0-SI-4.11.B.1.g, "High Pressure Fire Protection System Flow
 
Test," Revision 20, and concluded that the extent of the testing, the acceptance criteria, and the analysis of the test data outlined in the document is detailed and adequate to
 
assess the ability of the system to perform its intended function. The staff was satisfied
 
with the review; therefore, the staff found the exception acceptable.
Enhancement 1. In LRA Section B.2.1.24, the applicant proposed an enhancement that the FPR and procedures will be updated to include Unit 1 as an operating rather than a
 
shutdown unit. The Fire Water System Program will be fully implemented on Unit 1. This enhancement is scheduled for completion prior to the period of extended operation. This enhancement affects the program element "Scope of Program."
In evaluating the enhancement, the staff concluded that this enhancement will bring the AMP common to all units and will be updated to bring Unit 1 to an operating status, rather than shut down. The enhancement is, hence, acceptable.
Enhancement 2. In LRA Section B.2.1.24, the applicant proposed an enhancement. BFN will perform flow tests or non-intrusive exam inations (e.g., volumetric tests for wall thickness of fire protection system piping) to identify evidence of loss of material due to
 
corrosion. The applicant stated that these inspections will be performed before entering
 
the period of extended operation. This enhancement affects the program elements,"Parameters Monitored or Inspected" (Ele ment 3) and "Detection of Aging Effects"(Element 4).
Parameters Monitored or Inspected - In its evaluation, the applicant stated that the Fire Water System Program monitors parameters that indicate the systems' ability to maintain pressure and allow detection of internal system corrosion
 
conditions. The Fire Water System Program requires system and component testing and inspections as well as periodic flow testing. Wall thickness
 
evaluations are determined by the system engineer when systems are opened for maintenance and by pressure tests/leak detection. The Fire Water System
 
Program includes flow testing and system evaluations to ensure that the system maintains its intended function. The staff evaluated the program element together with the ISG-04 revised criteria for the GALL AMP XI.M27 for this program element. This revised guidance no
 
longer recommends the use of GL 89-13 in determining the system's ability to
 
maintain pressure and internal system corrosion conditions. Rather, ISG-04
 
recommends either periodic flow testing of the fire water system using the
 
guidelines of NFPA 25, at the maximum design-flow, or periodic wall-thickness
 
evaluations to ensure that the system maintains its intended function. Based on
 
the applicant's commitment to inspect fire water system components, the staff 3-69 determined that the program element is acceptable and that it complies with ISG-04 recommendations.
.Detection of Aging Effect - The applicant, in evaluating this element, stated that the environmental and material conditions that exist on the interior surface of the
 
below grade fire water system piping are similar to the conditions that exist within
 
the above-grade fire water system piping. The results of the inspections of the
 
above grade fire water system piping will be extrapolated to evaluate the condition of below-grade fire water system piping to ensure that the intended
 
function of below-grade fire water system piping will be maintained consistent
 
with the CLB for the period of extended operation. Repair and replacement
 
actions are initiated as necessary. The plant-specific inspection intervals are to
 
be determined by engineering evaluation of the fire protection piping to detect
 
degradation prior to the loss of intended function. The purpose is to ensure that
 
corrosion, MIC, or biofouling is managed such that the system function is
 
maintained. With the implementation of this enhancement, BFN will be consistent
 
with the affected program elements, except for the exception previously
 
described for the "Parameters Monitored or Inspected" element.
Based on the above evaluation of the two program elements,. the staff found that enhancement 2 is acceptable.
Enhancement 3. In LRA Section B.2.1.24, the applicant proposed an enhancement; that BFN will perform sprinkler head inspections before the end of the 50-year sprinkler head
 
service life and at 10-year intervals thereafter during the period of extended operation to
 
ensure that signs of degradation, such as corrosion, are detected in a timely manner.
 
This enhancement is scheduled for completion prior to exceeding the 50-year service life
 
for any sprinkler. This enhancement affects the program element "Detection of Aging
 
Effects" (Element 4).
Detection of Aging Effects - GALL AMP XI.M27 contains the criteria for the program element "Detection of Aging Effects." The applicant in evaluating this
 
element affected stated that a sample of sprinkler heads will be inspected using
 
the guidance of NFPA 25, 2002 Edition, Section 5.3.1.1.1. This NFPA section
 
states that "where sprinklers have been in place for 50 years, they shall be
 
replaced or representative samples from one or more sample areas shall be
 
submitted to a recognized testing laboratory for field service testing." It also
 
contains guidance to perform this sampling every 10 years after the initial field
 
service testing.
In evaluating this program element, the staff stated that ISG-04 revised criteriafor the GALL AMP XI.M27 "Detection of Aging Effects" program element
 
recommends sprinkler head inspections before the end of the 50-year sprinkler
 
head service life and at 10-year intervals thereafter during the period of extended
 
operation to ensure that signs of degradation are detected in a timely manner.
 
Based on the revised GALL Report criteria in ISG-04, and the applicant's
 
commitment to rely upon applicable codes and standards to develop test
 
procedures, the staff determined enhancement 3 to be acceptable.
3-70 Operating Experience. In LRA Section B.2.1.24, the applicant stated that the fire water system parameters are monitored and tested, and that piping and component evaluations are
 
performed to ensure that the system maintains its intended function. The BFN Fire Water
 
System operating experience indicates a trend of piping degradation, such as leaks, general
 
corrosion, and biofouling, etc. Piping is being replaced, as required, in accordance with
 
corrective actions of the inspection and testing activities. The applicant also stated that the
 
continued implementation of the Fire Water Sy stem Program provides reasonable assurance that aging effects will be managed so that the systems and components within the scope of this
 
program will continue to perform their intended functions consistent with the CLB for the period
 
of extended operation.
UFSAR Supplement. In LRA Section A.1.22, the applicant provided the UFSAR supplement for the Fire Water System Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the exception and the
 
associated justifications and determined that the AMP, with exceptions, is adequate to manage
 
the aging effects for which it is credited. Also, the staff reviewed the enhancements and
 
confirmed that the implementation of t he enhancements prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which
 
it was compared. The staff concluded that the applicant had demonstrated that the effects of
 
aging will be adequately managed so that the intended functions will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff
 
also reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.18  Fuel Oil Chemistry Program
 
Summary of Technical Information in the Application. The applicant's Fuel Oil Chemistry Program is described in LRA Section B.2.1.27, "
Fuel Oil Chemistry Program." In the LRA, the applicant stated that this is an existing program.
This program is consistent, with an exception,with GALL AMP XI.M30, "Fuel Oil Chemistry Program."
In LRA Section B.2.1.27, the applicant stated that the Fuel Oil Chemistry Program consists of surveillance and maintenance procedures to mitigate corrosion, and measures to verify the
 
effectiveness of the AMP and to confirm the absence of an aging effect. Fuel oil quality is
 
maintained by monitoring and controlling fuel oil contamination in accordance with the
 
guidelines of the American Society for Testing Materials (ASTM) Standards D 1796, D 2276, and D 4057. Exposure to fuel oil contaminants, such as water and microbiological organisms, is
 
minimized by periodic draining of water or cleaning of tanks and by verifying the quality of new
 
oil before its introduction into the storage tanks. Procedures require performance of fuel oil tank
 
bottom and multi-level sampling on a quarterly basis to detect and remove water and sediment
 
from each tank. In addition, each 7-day diesel oil supply tank is cleaned and inspected at
 
intervals of approximately 10 years. A one-time inspection in accordance with the One-Time
 
Inspection Program (B.2.1.29) will be performed prior to entering the period of extended 3-71 operation and will consist of thickness measurements of the 7-day diesel oil supply tanks and diesel driven fire pump fuel oil tank bottom surface.
The applicant also stated that this program provides a general description of items to be included within the scope of the program, but does not specifically identify the 7-day diesel oil
 
supply tank as an item to be inspected.
Portions of the Fuel Oil Chemistry Program ar e mandated by TS 5.5.9, "Diesel Fuel Oil Testing Program," that requires a diesel fuel oil testing program to implement required testing of the fuel oil in each 7-day fuel oil tank. The purpose of the program is to establish that the quality of the
 
fuel oil in each 7-day fuel oil tank is within the acceptable limits specified in Table 1 of ASTM
 
D-975-1989 when tested every 92 days; and total particulate concentration of the fuel oil in each
 
7-day fuel oil tank is less than 10 mg/l, when tested every 92 days in accordance with ASTM
 
D-2276, Method A-2 or A-3.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in its
 
BFN audit and review report. Furthermore, the staff reviewed the exception and justification to
 
determine whether the AMP, with the exception, remains adequate to manage the aging effects
 
for which it is credited.
The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the Fuel Oil Chemistry Program and associated bases document s, and compared them to those listed forAMP XI.M30 in the GALL Report for consistency.
In its response to RAI 7.1.19-1, by letter dated May 25, 2005, the applicant stated:
The One-Time Inspection Program (B.2.1.29) has been revised to specifically identify ultrasonic thickness measurements of the fuel oil storage tank bottom surfaces to ensure
 
that significant degradation is not occurring.
To implement this change, the "Program Description" section of LRA Appendix B.2.1.29, One-Time Inspection Program, has been revised to include the following item:
* Ultrasonic thickness measurements of tank bottoms to ensure that significant degradation is not occurring for those tanks specified in the Fuel Oil Chemistry
 
Program (B.2.1.27) and the Aboveground Carbon Steel Tanks Program (B.2.1.26).
The staff also reviewed BFN Procedure CI-130, "Diesel Fuel and Lube Oil Monitoring Program,"
and Procedure 0-SR-3.8.3.3 "Quarterly Fuel Oil Quality Determination of Unit 0 Diesel
 
Generator's 7-Day Storage Tank Supply."
Exception. In LRA Section B.2.1.27, the applicant identified an exception to GALL AMPXI.M30 that affects three program elements. The applicant does not use ASTM Standard
 
D 2709 for guidance on the determination of water and sediment contamination in diesel fuel, as specified in GALL AMP XI.M30. The applicant does implement ASTM Standard
 
D 1796 guidance on the determination of water and sediment contamination, which is also specified in GALL AMP XI.M30.
3-72 The staff evaluation of the affected GALL R eport program elements, "Scope of Program"(Element 1), "Parameters Monitored or Inspected" (Element 3), and "Acceptance Criteria" (Element 6), for the acceptability of the exceptions is as follows:
Scope of Program - The program is focused on managing the conditions that cause general pitting and MIC of the diesel fuel tank internal surfaces. The
 
program serves to reduce the potential of exposure of the tank internal surface to
 
fuel oil contaminated with water and microbiological organisms.
Parameters Monitored or Inspected - The Fuel Oil Chemistry Program monitors fuel oil quality and the levels of water and microbiological organisms in the fuel
 
oil, which cause the loss of material of the tank internal surfaces. The ASTM
 
Standard D 4057 is used for guidance on oil sampling. The ASTM Standards D
 
1796 and D 2709 are used for determination of water and sediment
 
contamination in diesel fuel. For determination of particulates, modified ASTM D
 
2276, Method A, is used. The modification consists of using a filter with a pore
 
size of 3.0 microns, instead of 0.8 microns. These are the principal parameters
 
relevant to tank structural integrity.
Acceptance Criteria - The ASTM Standard D 4057 is used for guidance on oil sampling. The ASTM Standards D 1796 and D 2709 are used for guidance on
 
the determination of water and sediment contamination in diesel fuel. Modified
 
ASTM D 2276, Method A is used for determination of particulates. The
 
modification consists of using a filter with a pore size of 3.0 microns, instead of
 
0.8 microns.
The applicant concluded that the ASTM D 1796 test method is an acceptable laboratory test method per ASTM D 975-89, "Standard Specification for Diesel Fuel Oils," for the
 
determination of water and sediment contamination in the Grade 2 fuel oil used at BFN.
Based on discussions with the applicant and review of implementing procedures, the staff determined that, for fuel oils with the viscosity used at BFN, only ASTM standard D
 
1796 is applicable. Therefore, the staff found this exception to be acceptable.
LRA Section B.2.1.27 did not identify any enhancements; however, the staff noted that anenhancement to achieve consistency with GALL AMP XI.M30, Element 4, "Detection of Aging
 
Effects," is identified in the applicant's AMP ev aluation basis document. Specifically, the existing Fuel Oil Testing and Monitoring Program needs to be enhanced to include ultrasonic thickness
 
measurements of the tank bottom surfaces to ensure that significant degradation is not
 
occurring.
The program description in LRA Section B.2.1.27 also identifies that a one-time inspection, in accordance with the One-Time Inspection Program, will be performed prior to entering the
 
period of extended operation and will consist of thi ckness measurements of the 7-day diesel oil supply tanks' bottom surface. The staff reviewed the One-Time Inspection Program and noted
 
that it provides a general description of items to be included within the scope of the program, but does not specifically identify the 7-day diesel oil supply tank as an item to be inspected.
3-73 The staff identified this issue in RAI 7.1.19-1, as documented in the staff's BFN audit and review report.In response to this audit RAI and staff follow up on the subject, the applicant stated in a docketed submittal dated May 25, 2005, as follows:
The One-Time Inspection Program (B.2.1.29) has been revised to specifically identify ultrasonic thickness measurements of the fuel oil storage tank bottom surfaces to ensure
 
that significant degradation is not occurring. To implement this change, the "Program
 
Description" section of LRA Appendix B.2.1.29, One-Time Inspection Program, has been
 
revised to include the following item: " Ultrasonic thickness measurements of tank
 
bottoms to ensure that significant degradation is not occurring for those tanks specified
 
in the Fuel Oil Chemistry Program (B.2.1.27) and the Aboveground Carbon Steel Tanks
 
Program (B.2.1.26)."
This program description change has been entered into a commitment item and will be suitably incorporated into the Commitment Table in SER Appendix A. The staff considers the response
 
to be acceptable.
Operating Experience. The Fuel Oil Chemistry Program includes identification of water and particulate contamination in the diesel fuel oil system. Corrective actions were taken for the
 
water and particulate contamination removal and system/component inspections. However, there have been no instances of fuel oil system component failures at BFN attributed to
 
contamination.
UFSAR Supplement. In LRA Section A.1.24, the applicant provided the UFSAR supplement for the Fuel Oil Chemistry Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined, those program elements for which the applicant claimed consistency with the GALL
 
Report are consistent with the GALL Report. In addition, the staff reviewed the exception and
 
the associated justifications and determined that the AMP, with the exception, is adequate to
 
manage the aging effects for which it is credited. In its review, the staff identified an
 
enhancement and confirmed that the implementati on of the enhancement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report
 
AMP to which it was compared. The staff concluded that the applicant had demonstrated that
 
the effects of aging will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.2.19  Reactor Vessel Surveillance Program
 
Summary of Technical Information in the Application. The applicant's Reactor Vessel Surveillance Program is described in LRA Section B.2.1.28, "Reactor Vessel Surveillance 3-74 Program." In the LRA, the applicant stated that this is an existing program. This program isconsistent, with enhancements, with GALL AMP XI.M31, "Reactor Vessel Surveillance."
The program was implemented to conform to the requirements of 10 CFR Part 50, Appendix H,"Reactor Vessel Material Surveillance Program Requirements." The Reactor Vessel
 
Surveillance Program is an integrated surveillance program in accordance with 10 CFR Part 50, Appendix H paragraph III.C, that is based on requirements established by the BWRVIP.
 
Referencing of BWRVIP activities for license renewal was approved by the staff in its SER
 
regarding BWRVIP-74 of October 18, 2001.
The applicant stated that the Reactor Vessel Surveillance Program is described in UFSAR Section 4.2.6 and is based on BWRVIP-78, "BWR Integrated Surveillance Program (ISP) Plan,"
 
and BWRVIP-86, "BWR Vessel And Internals Project, BWR Integrated Surveillance Program
 
Implementation." Use of the BWRVIP-78 and BWRVIP-86 was approved for referencing in the
 
staff's safety evaluation dated February 1, 2000. Use of the BWRVIP ISP at Units 2 and 3 was
 
approved by the staff in its safety evaluation dated January 28, 2003.
Enhancement 1. The applicant will confirm that the BWRVIP ISP for the period of extended operation, if approved by the staff for the BWR fleet, is applicable to each reactor vessel and will
 
request the approval from the NRC, if necessary, to use the program at applicable reactor
 
vessels for the period of extended operation. This enhancement is scheduled for completion
 
prior to the period of extended operation, and it affects the program element affected "Scope of
 
Program" (Element 1).
In the LRA, the applicant state that the BWRVIP ISP described in BWRVIP-78 and BWRVIP-86 is only applicable for current license term of 40 years. However, the BWRVIP-78 and
 
BWRVIP-86 ISP provides for 13 capsules to be available for testing during the license renewal
 
period for the BWR fleet and establishes acceptable technical criteria for capsule withdrawal
 
and testing. The BWRVIP has submitted a report, BWRVIP-116, which provides the basis and
 
plan for extending the BWR ISP to address potential extended periods of operation for each unit
 
in the existing U.S. BWR fleet. The staff's review of BWRVIP-116 is not complete. When the
 
staff review of BWRVIP-116 is complete, the applicant stated that it will evaluate the SER and
 
complete any SER Action Items.
The applicant committed to implement the requirements of BWRVIP-116, when approved, for all three reactor vessels. Therefore, the applicant did not submit a plant-specific program in its
 
LRA.Enhancement 2. The applicant indicated in the LRA that for Unit 1 it would submit for staff approval the BWRVIP ISP, or a plant-specif ic surveillance program, that meets the requirements of 10 CFR Part 50, Appendix H for the period of extended operation. The
 
applicant proposed to implement the following actions:
* Capsules will be removed periodically to determine the rate of embrittlement and at least one capsule with neutron fluence of not less than once or greater than twice the peak
 
beltline neutron fluence will be removed before the expiration of the license renewal
 
period.
* Capsules will contain material to monitor the impact of irradiation on the limiting beltline materials and will contain dosimetry to monitor neutron fluence.
3-75
* If capsules are not being removed during the license renewal period, operating restrictions (i.e., inlet temperature, neut ron spectrum, and flux) will be implemented with NRC approval to ensure that the reactor vessel is operating within the environment of
 
the surveillance capsules, and ex-vessel dosimetry will be supplied for monitoring neutron fluence. This enhancement is scheduled for completion prior to the period of
 
extended operation.
The applicant indicated that a plant-specific withdrawal schedule of the surveillance capsules will be submitted to NRC for final approval in accordance with 10 CFR Part 50, Appendix H prior
 
to entering the period of extended operation.
The applicant concluded that with the implementation of these enhancements, the Reactor Vessel Surveillance Program will be consistent with GALL with respect to the scope of program
 
element for all three units, and this program provides reasonable assurance that the aging
 
effects will be managed so that the systems and components within the scope of this program will continue to perform their intended functions, consistent with the CLB basis, for the period of
 
extended operation.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancements and their
 
justifications to determine whether the AMP, with enhancements, remains adequate to manage
 
the aging effects for which it is credited.
In LRA Section B.2.1.28, the applicant described the Reactor Vessel Surveillance Program to manage irradiation embrittlement of the RV through testing that monitors RV beltline materials.
 
The LRA states that the Reactor Vessel Surveillance Program will be enhanced by making it
 
consistent with the BWRVIP ISP for periods of extended operation prior to the BFN units
 
entering their period of extended operation. The LRA further states that the enhanced program will be consistent with GALL AMP XI.M31, "Reactor Vessel Surveillance," described in the GALL
 
Report. For this AMP, the GALL Report recommends further evaluation. The staff also reviewed
 
the UFSAR supplement to determine whether it provides an adequate description of the
 
program. The applicant has implemented the BWRVIP ISP (as documented in BWRVIP-86-A) consistentwith the GALL AMP XI.M31, "Reactor Vessel Surveillance," described in the GALL Report for
 
the period of the current units' licenses. The staff concluded that the BWRVIP ISP in
 
BWRVIP-86-A is acceptable for BWR applicant implementation provided that all participating
 
applicants use one or more compatible neutron fluence methodologies acceptable to the staff
 
for determining surveillance capsule and RPV neutron fluences. Staff acceptance of the
 
BWRVIP ISP for the current term is documented in the SER dated February 1, 2002, from Bill
 
Bateman (NRC) to Carl Terry (BWRVIP Chairm an). BWRVIP-116 provides guidelines for an ISP to monitor neutron irradiation embrittlement of the reactor vessel beltline materials for all U.S.
 
BWR power plants for the period of license renewal.
The staff's review of LRA Section B.2.1.28 identified areas in which additional information was necessary to complete the review of the applicant's program elements. The applicant responded
 
to the staff's RAI as discussed below.
3-76 In RAI B.2.1.28-1(A), dated December 1, 2004, the staff requested the applicant to make a commitment to implement BWRVIP-116 ISP, which is currently being reviewed by the staff, or to submit a plant-specific surveillance program for each unit, two years prior to entering the period of extended operation.
In its response, by letter dated January 31, 2005, the applicant indicated that it will implement either BWRVIP-116, as approved by the staff or , if the ISP is not approved two years prior to entering the BFN units' period of extended operation, submit to the staff a plant-specific
 
surveillance program for each unit. The applicant also stated that it will revise LRA
 
Section A.1.25 as shown in the subsection "UFSAR Supplement" of this section. This program
 
description change has been entered into a commitment item and will be suitably incorporated
 
into the Commitment Table in SER Appendix A.
The staff reviewed the applicant's response and determined that the applicant must make a formal commitment indicating that it will incor porate BWRVIP-116 as approved by the staff or a plant-specific RV surveillance program for each unit, that will satisfy the requirements of
 
10 CFR Part 50, Appendix H.
In RAI B.2.1.28-1(B), dated December 1, 2004, the staff requested that the applicant provide an explanation for not including Unit 1 in the ISP. The staff also requested that the applicant
 
provide a plant-specific surveillance program for Unit 1, or discuss how Unit 1 will be
 
incorporated into BWRVIP-116, and provide an evaluation of the vessel-to-capsule material
 
compatibility for the limiting plate and weld, as was performed for the ISP program, similar to the
 
other plants specified in BWRVIP-86 and BWRVIP-116.
In its response, by letter dated January 31, 2005, the applicant indicated that LRA Section B.2.1.28 discusses Unit 1 enhancements required to the Reactor Vessel Surveillance
 
Program. The applicant stated in LRA Section B.2.1.28 that, "Unit 1 will be included within the
 
BWRVIP Integrated Surveillance Program, or a plant-specific surveillance program will be submitted for NRC approval that meets the requirements of 10 CFR Part 50, Appendix H for the
 
period of extended operation."
The applicant indicated that the BWRVIP evaluated the Unit 1 Vessel and Surveillance Program for participation in the ISP. The BWRVIP proposed in its letter from William A. Eaton (Chairman, BWRVIP) to the NRC Document Control Desk, "Project No. 704 - BWRVIP Response to NRC
 
RAIs on BWRVIP-116," dated January 11, 2005, to include Unit 1 in the ISP. The BWRVIP
 
indicated that Unit 1 is similar in design to the other BWRs in the ISP, and there are no
 
differences in irradiation conditions from the BWR fleet. The BWRVIP evaluated the Unit 1
 
Reactor Vessel and Surveillance Program for participation in the ISP, consistent with the
 
methods and criteria previously established in BWRVIP-78 and BWRVIP-86 reports. The test
 
capsules representing limiting weld and plate materials are exposed to fluence values that
 
bound Unit 1 extended end of life (EOL) period fluences at the vessel 1/4 t location. Based on the information provided in the submittal, the staff concluded that the proposed representative
 
materials that are available for use in the ISP for Unit 1 could adequately provide information
 
related to any changes in the fracture toughness properties due to irradiation for the limiting
 
beltline materials during the period of extended operation.
In RAI B.2.1.28-1(C), dated December 1, 2004, the staff requested that the applicant provide its plan associated with testing of the capsules in accordance with the requirements of 3-77 BWRVIP-116 ISP. The plan should also identify capsules that need not be tested (standby capsules). Tables 2-3 and 2-4 of BWRVIP-116 indicate that capsules from Unit 2 will be tested
 
and capsules from Unit 3 (standby capsules) will be not tested. These untested capsules were originally part of the applicant's plant-spec ific surveillance program and have received significant amounts of neutron radiation. The staff requested the applicant to provide its
 
intentions with regard to maintenance of the standby capsules for further use.
In its response, by letter January 31, 2005, the applicant stated:
Presently, there are no plans to withdraw surveillance capsules from the Unit 3 reactor vessel since the BFN Unit 2 reactor vessel capsule provides the best representative
 
material for both units. As stated in NRC Safety Evaluation of the BWRVIP Integrated
 
Surveillance Program, dated February 1, 2002: "Although some surveillance capsules
 
will be deferred and not tested as part of the ISP, all capsules that were previously
 
credited as part of plant-specific surveillance programs will continue to be irradiated in
 
their host reactors. Therefore, all irradiated material samples continue to remain
 
available to the ISP, if needed, and no overall reduction in the number of materials being
 
irradiated, number of specimen types, or number of specimens per reactor occurs as a result of the ISP." Unit 3 surveillance capsules will remain in place and will continue to
 
be irradiated during plant operation, including the period of extended operation.
 
Therefore, the Unit 3 irradiated material samples continue to remain available to the ISP, if needed.
 
In response the staff requested the following standard license condition required of all LRA
 
applicants to be included in the SER (see SER Section 1.7):
Any changes to the BWRVIP ISP capsule withdrawal schedule must be submitted for staff review and approval. Any changes to the BWRVIP ISP capsule withdrawal
 
schedule which affects the time of withdrawal of any surveillance capsules must be
 
incorporated into the licensing basis. If any surveillance capsules are removed without
 
the intent to test them, these capsules must be stored in manner which maintains them
 
in a condition which would support reinsertion into the RV, if necessary.
On the basis of its review, the staff found the applicant had demonstrated that the effects of aging due to loss of fracture toughness of the RV beltline region will be adequately managed
 
with the exceptions as stated above, so that the intended functions will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
Operating Experience. The applicant successfully implemented its Reactor Vessel Surveillance Program that is consistent with RG 1.99, Revision 2, 10 CFR Part 50, Appendix H, and ASTM E
 
185, "Conducting Surveillance Tests For Light Water Cooled Reactor Vessels, E-706,"
 
predictions.
UFSAR Supplement. In LRA Section A.1.25, the applicant provided the UFSAR supplement for the Reactor Vessel Surveillance Program.
As noted above, in its response to RAI B.2.1.28-1(A), by letter dated January 31, 2005, the applicant stated that it will revise LRA Section A.1.25 as follows:
3-78 The BFN Reactor Vessel Surveillance Program is mandated by 10 CFR Part 50 Appendix H. The BFN Reactor Vessel Surveillance Program is an integrated
 
surveillance program in accordance with 10 CFR Part 50 Appendix H Paragraph III.C
 
that is based on requirements established by the BWR Vessel and Internals Project.
 
This program will be enhanced to implement ei ther BWRVIP-116, as approved by the staff, or, if the ISP is not approved two years prior to the commencement of the license
 
renewal period, a plant-specific surveillance program for each BFN unit will be submitted
 
that ensures the BFN Unit 1, Unit 2, and Unit 3 reactor vessels meet the requirements of
 
10 CFR Part 50 Appendix H.
The applicant described the Reactor Vessel Surv eillance Program as an existing program in LRA Section A.1.25. The program uses periodic testing of metallurgical surveillance samples to
 
monitor the loss of fracture toughness of the RPV beltline region materials consistent with the
 
requirements of 10 CFR Part 50, Appendix H and ASTM E 185. In its response regarding the
 
standby capsules (stated above), the applicant indicated that it would use Unit 3 surveillance
 
capsules as standby capsules for the period of extended operation.
In a follow up on March 29, 2005, to RAI B.2.1.28-1(A), the staff requested the applicant to commit that any changes to the BWRVIP ISP capsule withdrawal schedule must be submitted
 
for staff review and approval. Any changes to the BWRVIP ISP capsule withdrawal schedule
 
that affects the time of withdrawal of any surveillance capsules must be incorporated into the
 
licensing basis. If any surveillance capsules are removed without the intent to test them, these
 
capsules must be stored in a manner that maintains them in a condition that would support
 
re-insertion into the RV, if necessary. Units 1 and 3 surveillance capsules (standby capsules)
 
will remain in place and will continue to be irradiated during plant operation, including the period
 
of extended operation. Therefore, Units 1 and 3 irradiated material samples continue to remain
 
available to the ISP, if needed.
In its response dated May 25, 2005, the applicant agreed to comply with the staff request. This satisfactorily resolves the staff RAI B.2.1.28-1(A). This program description change has been
 
entered into a commitment item and will be suitably incorporated into the Commitment Table in
 
SER Appendix A.
The staff reviewed the applicant's proposed revision to LRA Section A.1.25 and determined that the applicant must implement the most recent staff-approved version of the BWRVIP ISP as the
 
method to demonstrate compliance with the requirements of 10 CFR Part 50, Appendix H.
The staff concluded that the information provided in the UFSAR supplement for the aging management of systems and components discussed abov e is equivalent to the information in the SRP-LR and, therefore, provides an adequate summary of program activities as required by
 
10 CFR 54.21(d).
Conclusion. On the basis of its review, RAI responses, and audit of the applicant's program, the staff found that those program elements for which the applicant claimed consistency with the
 
GALL Report are consistent with the GALL Report. In addition, the staff reviewed the
 
enhancements and confirmed that the implementat ion of the enhancements prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report
 
AMP to which it was compared. The staff found that the applicant had demonstrated that the
 
effects of aging will be adequately managed so that the intended functions will be maintained 3-79 consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).3.0.3.2.20  ASME Section XI Subsection IWE Program
 
Summary of Technical Information in the Application. The applicant's ASME Code Section XISubsection IWE Program is described in LRA Section B.2.1.32, "ASME Section XI Subsection
 
IWE Program." In the LRA, the applicant stated t hat this is an existing program. This program isconsistent, with exceptions, with GALL AMP XI.S1, "ASME Section XI Subsection IWE."The ASME Section XI Subsection IWE Inservice Inspection Program includes visual examination and augmented inspection (visual and/
or volumetric examinations) for steel containments (Class MC). Inspections or testing are conducted on the steel containment shells
 
and their integral attachments; containment hatches and airlocks; seals, gaskets, and moisture
 
barriers; and pressure-retaining bolting. As required by 10 CFR 50.55a paragraph (g)(4)(ii), the ASME Code Section XI Subsection IWE Inservice Inspection Program will incorporate the
 
requirements of the latest edition and addenda of the ASME Code by reference into
 
10 CFR 50.55a paragraph (b) 12 months prior to the start of each 120-month inspection interval, subject to the limitations and modifications listed in 10 CFR 50.55a paragraph (b) and with
 
alternatives as authorized by the staff in accordance with 10 CFR 50.55a paragraphs (a)(3) and (g)(6). Inspection of Class MC components, covered in the subsection IWE, is performed in
 
accordance with the 1992 edition through 1992 addenda for BFN current inspection intervals.
Based on the description of the program, the applicant, in its evaluation of the AMP, concludedthat the continued implementation of the ASME Code Section XI Subsection IWE Inservice
 
Inspection Program provides reasonable assurance that the aging effects will be managed so
 
that the structures within the scope of this program will continue to perform their intended
 
functions consistent with the CLB for the period of extended operation.
Staff Evaluation. During its review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the BFN audit and
 
review report. Furthermore, the staff reviewed the exceptions and their justifications to
 
determine whether the AMP, with exceptions, remains adequate to manage the aging effects for
 
which it is credited.
The staff evaluation consists of identifying and accepting departures from the provisions of the GALL Report. In the program description, the applicant takes three exceptions, which are
 
discussed as follows.
Exception 1. The ASME Code Section XI, 1992 Edition, 1992 Addenda requires visual examination VT-3 of containment seals and gaskets. In lieu of a visual examination, BFN takes
 
an exception to this requirement and requests exception that the test be performed in
 
accordance with the 10 CFR 50 Appendix J Program to determine degradation of seals and
 
gaskets. The applicant, in evaluating this exception, stated that examination of most seals and
 
gaskets require the joints to be disassembled. When the airlocks, hatches, electrical
 
penetrations, and flanged connections are tested in accordance with 10 CFR 50 Appendix J, degradation of the seal or gasket material is revealed by an increase in the leakage rate.
3-80 Corrective measures can then be applied and the component re-tested. The applicant received a relief from these requirements for Units 2 and 3 for the current interval.
Exception 2. The applicant seeks a second exception to the ASME Code of record for BFN, which requires torque or tension testing on pressure-retaining bolted connections that have not
 
been disassembled and reassembled during the inspection interval. The applicant, however, seeks to perform a test conforming to 10 CFR 50 Appendix J testing in lieu of a bolt torque or
 
tension test as required by the Code for these bolted connections. There is current relief that
 
authorizes this for Units 2 and 3 for the current interval.
Exception 3. The applicant seeks a third exception to the ASME Code, which requires that, when component examination results require ev aluation of flaws, areas of degradation, or repairs in accordance with article IWE-3000, and the component is found to be acceptable for
 
continued service, the areas containing such fl aws, degradation, or repairs shall be reexamined during the next inspection period listed in the schedule of the inspections program. When the
 
reexaminations reveal that the flaws, areas of degradation, or repairs remain essentially
 
unchanged for three consecutive inspection periods, the areas containing such flaws, degradation, or repairs no longer require augmented examination in accordance with
 
Table IWE-2500-1 Examination Category E-C. At BFN, if the repair has restored the component
 
to an acceptable condition, reexaminations during subsequent inspection periods are not
 
performed.  (1)Scope of Program - In the LRA, the scope of the program is as described in IWE-1000 of Subsection IWE, of the ASME Code together with the exemptions as identified in
 
IWE-1220, and additional requirements for inaccessible areas as promulgated in
 
10 CFR 50.55a(b)(2)(ix). The staff found that the plant-specific program scope is in conformance with Section XI.S1 of the GALL Report. Therefore, the staff found the
 
program element acceptable.  (2)Preventive Action - The applicant does not take exception to the program element.
  (3)Parameters Monitored or Inspected - The staff evaluated this program element and studied the impacts on Exceptions 1 and 2.
Staff evaluation: Exception 1 - ASME Code Examination Category E-D of Table IWE-2500-1 requires visual examination of pressure boundary seals and gaskets.
 
The applicant stated in Exception 1 that it utilizes tests performed in accordance with
 
10 CFR 50 Appendix J, in lieu of a visual examination, to determine degradation of seals
 
and gaskets. In order to evaluate the exception, the staff needed additional information.
In RAI 3.5-2, dated December 10, 2004, the staff inquired about the aging management of containment penetration seals and gaskets by pointing out that seals and gaskets
 
related to containment penetrations (in Item Number 3.5.1-6 of Table 3.5.1) are
 
proposed to be managed by the Containment Inservice Inspection Program and the Containment Leak Rate Testing Program. As a result of Exception 1 to the ASME Code Section XI Subsection IWE Program, the staff questioned whether the AMP will be
 
applicable for aging management of containment seals and gaskets. The staff said that
 
for equipment hatches and air-locks at BFN, the approach is that the leak rate testing
 
program will monitor aging degradation of seals and gaskets, as they are leak rate
 
tested after every opening. The staff wanted the applicant to clarify whether the
 
assumptions are correct. The staff also requested information for mechanical and 3-81 electrical penetrations with seals and gaskets, if the Type B leak rate testing and frequency was adequate to monitor aging degradation of seals and gaskets of
 
containment drywell. The staff also requested the status of inspection and conditions of
 
the seals and gaskets of these penetrations at Unit 1.
With regard to Unit 1, the applicant stated that a Type B test will be performed as part of the Unit 1 restart effort, and will continue to test at a frequency of 30 months until
 
sufficient test performance data are available to justify an extended test interval under
 
Option B.Details of RAI 3.5-2 are provided in SER Section 3.5.2.3.1. The staff, in evaluating the applicant response, concluded that the applicant satisfactorily described the existing
 
process used in identifying degradation of the primary containment penetration seals
 
and gaskets. Also, since the applicant plans to continue with the testing and corrective
 
action process during the period of extended operation, the staff found the applicant's
 
process of managing the aging of the pressure-retaining seals and gaskets of primary
 
containments and the exception under this program element acceptable.
Staff evaluation of Exception 2 - ASME Code requires torque testing of pressure-retaining bolts of Examination Category E-G, item E8.2 of Table IWE-2500-1.
 
The applicant in exception 2, takes except ion from the ASME requirement and requests to perform a test conforming to 10 CFR Part 50, Appendix J testing in lieu of a bolt
 
torque or tension test. The staff has provided relief to this IWE requirement to a number
 
of PWR licensees; however, in the case of BWR containments, the staff has a concern
 
about the adequacy of Type A, Appendix J, leak rate testing to monitor the aging
 
degradation of drywell head bolts, particularly as the Type A testing interval has been
 
extended to 10 and 15 years. During the AMR results review, staff developed RAI 3.5-3
 
for the applicant's response.
In RAI 3.5-3, dated December 10, 2004, the staff requested information about the testing and inspection of drywell-head components by noting that the containment drywell-head
 
to drywell joint consists of a pressure unseating containment boundary with pre-loaded
 
bolts. Loosened bolts and deteriorated gasket and/or seal can breach containment
 
pressure boundary. The staff felt that Exceptions 1 and 2, taken in the containment ISI
 
program will preclude examinations of seals and bolts of this joint. The staff contended
 
that only Type A leak rate testing and associated visual examination requirements of
 
Appendix J Program can be relied upon to detect defects and degradation of this joint, whose test interval can be 10 to 15 years. The applicant was requested to provide
 
information regarding the plans and programs that are used to ensure the integrity of this
 
joint for each containment. The staff also requested the applicant to provide the status of
 
the components (O-rings and bolts) at this joint for Unit 1.
In its response to RAI 3.5-3, dated January 31, 2005, the applicant stated that these containment pressure boundary components will continue to be inspected consistent
 
with the BFN CLB under 10 CFR Part 50, Appendix J Program requirements. On Units 2
 
and 3 the Type A test frequency is currently on a 10-year interval. There have been no
 
performance-based Type A test failures on Units 2 or 3. The applicant in its response
 
stated that a Type A Integrated Leak Rate Test will be performed on Unit 1
 
prior-to-restart. Type B testing is also performed on the drywell-head seal every refueling
 
outage for all three units. Therefore, with the combination of the Type A tests and Type
 
B tests, integrity for this joint for each containment is assured. Exception 2 pertains to 3-82 bolt torque or tension testing. Pressure-retaining bolting associated with the containmentdrywell-head to drywell joint is examined in accordance with ASME Code Section XI, Subsection IWE. The staff is satisfied that these two activities together with periodic
 
Type A testing will ensure the integrity of this joint.
Therefore, the staff found the applicant's practice of ensuring the integrity of this joint acceptable and the exception 2 as proposed is acceptable.  (4)Detection of Aging Effects - The applicant does not take exception to the program element.  (5)Monitoring and Trending - The staff evaluated this program element and studied the impacts of exception 3 on it. This excepti on concerns component examination results that require evaluation of flaws, areas of degradation, or repairs in accordance with
 
Article IWE-3000, of ASME B&PV code (see above). The applicant in performing a
 
plant-specific evaluation of this element stated that the staff previously granted the
 
applicant a relief request (CISI-3) for Units 2 and 3 for its current inspection intervals
 
from the requirement of Paragraphs IWE-2420(b) and IWE-2420(c) to perform
 
reexaminations during subsequent inspection periods of the repaired areas if the repair
 
has restored the component to an acceptable condition. In evaluating the exception, the
 
staff took the position that if flaws and degradations had been repaired and restored in
 
accordance with the requirements of IWA-4000, the staff provided relief to a number of
 
licensees (and applicants) from the requirements of IWE-2420(b) and (c). In granting
 
that relief, staff considered the requirements as an unnecessary burden without a
 
commensurate safety benefit. Therefore, the staff found the exception as it impacted this
 
program element acceptable.  (6)Acceptance Criteria - Acceptable, as no exception taken to GALL AMP X1.S1.
  (7)Corrective Actions - The applicant does not take exception to the program element.
  (8)Confirmation Process - Acceptable, as no exception taken to GALL AMP X1.S1.
  (9)Administrative Controls - Acceptable, as no exception taken to GALL AMP X1.S1.
  (10)Operating Experience - The applicant reviewed plant-specific ASME Section XI, Inservice Inspection Program performance re sults that have been generally effective in managing aging effects in ASME components. In LRA Section B.2.1.32, the applicant
 
provided the following description of plant-specific operating experience.
The drywell steel containment vessel is inaccessible (except for the drywell head) for visual examination from the outside surface. There has been evidence of water leaking from the sand bed drains on both Units 2 and 3. Since there is a horizontal weld connecting the first and
 
second course of drywell liner plates approximately 8 inches above the drywell concrete floor, UT thickness measurements from the drywell floor up to this weld around the drywell
 
circumference would conservatively bound the sand pocket area. UT thickness measurements of this area were obtained during the U2C10 and U3C8 refueling outages for Units 2 and 3, respectively, and in 1999 and 2002 for Unit 1. The data indicated that the condition of the
 
drywell steel liner plate in this area is good, and that this area did not require augmented
 
examination.
The internal drywell steel containment vessel embedment zone is subject to corrosion if the drywell floor-to-containment vessel moisture barrier fails, allowing moisture intrusion; or if the 3-83 concrete floor of the drywell cracks, allowing moisture seepage through to the steel liner. During the Unit 2 U2C9 outage, a portion of the moisture barrier was replaced. Inspection of the
 
exposed drywell steel containment vessel area below the moisture seal indicated some minor
 
pitting and localized rust, but there was not a challenge to nominal wall thickness. No
 
propagation of iron oxide to the concrete surface was noted; its presence would have indicated
 
steel containment vessel corrosion below the concrete. The concrete floor above the embedded
 
steel containment vessel is examined as part of the Structures Monitoring Program (B.2.1.36).
Based on existing inspection documentation and maintenance practices, this area has not
 
exhibited signs of accelerated degradation.
The penetration bellows at BFN have no documented failures as a result of routine testing by the BFN Appendix J program or inspections conducted by the Containment Inservice Inspection
 
Program.Inspections conducted under the Containment Inservice Inspection Program identified some damaged areas of the moisture seal barrier (gaps, cracks, low areas/spots, or other surface
 
irregularities) in Units 2 and 3 that required repair.
Operating experience related to containment structure components
: RAI 3.5-5, dated May 24, 2005, provides the details of the follow-up to RAI 3.5-4. The staff found that the applicant
 
comprehensively addressed all the issues. In closing out RAI 3.5-5, the staff concluded that the
 
applicant's program was adequate and acceptable. The disposition and resolution of RAI 3.5-5
 
can be found in SER Section 3.5.2.3.1.
Operating experience related to torus shells:
NRC IN 88-82, "Torus Shells with Corrosion and Degraded Coatings in BWR Containments," describes and discusses the problems associated
 
with corrosion of torus shells. In RAI B.2.1.32-1, dated December 10, 2004, the staff asked the
 
applicant to provide information regarding the status of torus shells. In applying NRC IN 88-82, the staff requested the applicant to provide operating experience related to inspection of torus
 
shells at BFN. since the quality of torus water in Unit 1 torus may not have been monitored
 
during its long layup period, the staff requested additional discussion of the condition of the
 
torus for Unit 1.
In its response, by letter January 31, 2005, the applicant stated that the torus interior surfaces at the waterline were subject to corrosion due to moisture and repeated wetting and drying in the
 
waterline region. Accessible portions of the torus inside surface were inspected each refueling
 
outage. UT thickness measurements taken in torus underwater areas of both Units 2 and 3
 
revealed no evidence of excessive degradation (all readings were within 10 percent of nominal
 
wall thickness). The applicant confirmed that previous inspections had documented evidence of
 
minor coating degradation at the waterline region. Based on the above, the applicant concluded
 
that the underwater region of the torus had not been subjected to accelerated degradation.
The applicant, furthermore, stated that, since evidence of repeated loss of coatings had been documented in the waterline region, augmented examination of this area was warranted as a
 
conservative measure on Units 2 and Unit 3.
Regarding Unit 1, the applicant stated that during its layup period, the water in the Unit 1 torus (pressure suppression pool) was maintained by the "chemistry program." The torus was drained
 
in the summer of 2003 for coating repair, which will be completed as a part of the Unit 1 3-84 recovery effort. The applicant also stated that a VT-3 visual examination was performed on the Unit 1 torus in August 2003. This examination included 100 percent of the Code Class MC
 
boundary inside the torus, which included shell and ring girders, and both sides of the vent
 
system to include main vent line, vent header , and downcomers. The visual examination found light-to-medium rust or discoloration in several areas and heavy rust in smaller, less frequent
 
areas. There were also some instances of base metal encroachment, such as gouges, scratches, and tool marks. Engineering evaluation of the examination results determined that
 
the torus structural condition was acceptable as is, with no base metal repairs required.Moreover, the applicant emphasized that the requirements of ASME Section XI Inservice Inspection Subsection IWE, 1992 Edition with the 1992 Addenda will be implemented on Unit 1.
 
Type A, B, and C leak rate testing required by 10 CFR 50, Appendix J will also be performed
 
prior to Unit 1 restart.
The applicant reviewed site-specific work history data to confirm that an adequate number of inspection opportunities are afforded by the IWE program. The applicant also stated in the LRA
 
that the plant Corrective Action Program, which captures internal and external plant operating
 
experience issues, provides reasonable assuranc e that operating experience will be reviewed in the future to provide objective evidence to support the conclusion that the effects of aging will
 
be managed adequately.
The staff found the applicant's process of monitoring the condition of the torus in Units 2 and 3 acceptable, as its continuation during the period of extended operation provides adequate
 
assurance regarding the ability of the torus to perform its intended function. The applicant stated
 
in its response letter dated January 31, 2005, that it monitored the quality of water and condition
 
of torus surfaces in the immediate past (since 2003), and plans to continue the ISI activities in
 
accordance with this AMP. Therefore, the staff found the applicant's procedures acceptable, as
 
they will ensure the ability of the torus to perform its pressure-retaining function during the
 
period of extended operation.
UFSAR Supplement. In LRA Section A.1.29, the applicant provided the UFSAR supplement forthe ASME Code Section XI Subsection IWE Program. The staff reviewed this section and
 
determined that the information in the UFSAR supplement provides an adequate summary
 
description of the program. The staff found this section of the UFSAR supplement met the
 
requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review, RAI responses, and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with
 
the GALL Report are consistent with the GALL Report. In addition, the staff reviewed the
 
exceptions and the associated justifications and determined that the AMP, with exceptions, is
 
adequate to manage the aging effects for which it is credited. The staff concluded that the
 
applicant had demonstrated that the effects of aging will be adequately managed so that the
 
intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement
 
for this AMP and concluded that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-853.0.3.2.21  ASME Section XI Subsection IWF Program Summary of Technical Information in the Application. The applicant's ASME Code Section XISubsection IWF Program is described in LRA Section B.2.1.33, "ASME Section XI Subsection
 
IWF Program." In the LRA, the applicant stated t hat this is an existing program. This program isconsistent, with an exception, with GALL AMP XI.S3, "ASME Section XI Subsection IWF."
The LRA states that 10 CFR 50.55a imposes the inservice inspection requirements of theASME B&PV Code Section XI for Class 1, 2, and 3 piping and component supports. Inspection
 
of equivalent Class 1, 2, and 3 piping and component supports covered in subsection IWF is
 
performed in accordance with the 1995 edition through the 1996 addenda for the Units 1 and 2
 
current inspection interval. Inspection of equivalent Class 1, 2, and 3 piping and component
 
supports covered in subsection IWF is performed in accordance with the 1989 edition and Code
 
Case N-491 "Alternative Rules for Examination of Class 1, 2, 3, and MC Component Supports of Light-Water Power Plants, Section XI Division 1," for the Unit 3 current inspection interval.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the exception and its justifications
 
to determine whether the AMP, with an exception, remains adequate to manage the aging
 
effects for which it is credited.
In RAI B.2.1.33-1, dated December 13, 2004, the staff requested the applicant to address how the supports of MC piping and components are inspected during the current licensing term.
In its response, by letter dated January 18, 2005, the applicant stated:
The Class MC boundaries include the steel containment vessel (SCV), which is comprised of the drywell, pressure suppression chamber or torus and associated vent
 
piping, including vertical and circumferential structural stiffeners; penetrations, reinforcement structure, the portion of the SCV embedded in the drywell concrete floor
 
slab, and attachment welds between structural attachments and the SCV pressure
 
retaining boundary or reinforcing structure.
The applicant stated that there is no Class MC piping at BFN. Piping in the scope of license renewal located in the containment that is not ASME equivalent Class 1, 2, or 3 is evaluated as
 
non-ASME piping, and covered in its AMR. The staff considered the above classification of the
 
MC component supports to be acceptable. Therefore, the staff's concern described in
 
RAI B.2.1.33-1 is resolved with regard to piping.
By letter dated January 24, 2005, the applicant responded that the ASME equivalent supports and component listed in LRA Table 2.4.8.1 do not include the drywell lower ring support and
 
the drywell upper lateral support. The staff was not clear regarding the applicant's basis for excluding the supports for Class MC components from the scope of ASME Section XI. The staff
 
requested that the applicant justify the above noted exclusion. In its response, by letter dated May 31, 2005, the applicant stated that it will manage the Class MC supports per Section XI, Subsection IWF. LRA Table 3.5.2.26 has been revised to reflect this commitment. Therefore, the staffs concern described in RAI B.2.1.33-1 is resolved with regard to support.
3-86 In RAI B.2.1.33-3, dated December 13, 2004, the staff requested the applicant to describe the method by which the supports on Class MC components in inaccessible areas will be managed
 
during the period of extended operation because the applicant's discussion of the IWF Program
 
is focused on accessible supports on MC components. There is no discussion of components in
 
inaccessible areas. In its response, by letter dated January 18, 2005, the applicant stated that
 
none of the torus cradles, downcomer supports, or vent header supports located in containment
 
air or inside air environments are inaccessi ble. For the vent downcomer and vent header supports that are submerged in a torus water environment, the applicant stated that the
 
Chemistry Control Program and One-Time In spection Program will be used to manage the aging effects. The staff considered the applicant's response to have adequately addressed its
 
concern on the aging management of inaccessible supports of MC components. RAI B.2.1.33-3
 
is, therefore, closed.
Based on the information provided in the LRA and the applicant's responses to the RAIs, the staff finds that the applicant's IWF Program is acceptable. The supports of MC components will
 
be adequately managed during the period of extended operation.
Operating Experience. The applicant did not indicate any adverse operating experience for this program.UFSAR Supplement. In LRA Section A.1.30, the applicant provided the UFSAR supplement for the IWF Inspection Program The staff reviewed this section and determined that the information
 
in the UFSAR supplement provides an adequate summary description of the program. The staff
 
found this section of the UFSAR supplement met the requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review, the staff found that the applicant's IWF program isconsistent with Section XI.S3 of the GALL. Based on the information provided by the applicant, the staff concluded that the accessible supports of the MC components will be adequately
 
inspected by the IWF Program during the period of extended operation. The staff concluded that
 
the effects of aging will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB during the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement program summary for the
 
IWF Program and concluded that, it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.22  Masonry Wall Program
 
Summary of Technical Information in the Application. The applicant's Masonry Wall Program is described in LRA Section B.2.1.35, "Masonry Wall Program." In the LRA, the applicant stated
 
that this is an existing program. This program is consistent, with an enhancement, with GALL AMP XI.S5, "Masonry Wall Program."
In LRA Section B.2.1.35, the applicant stated that the Masonry Wall Program provides for condition monitoring of masonry walls. The program is included in the Structures Monitoring
 
Program that implements the structures monitoring requirements of 10 CFR 50.65 Maintenance
 
Rule. Masonry wall condition monitoring is based on guidance provided in NRC Bulletin 80-11
 
"Masonry Wall Design" and IN 87-67 "Lessons Learned from Regional Inspections of Licensee
 
Actions in Response to I.E. Bulletin 80-11." Vis ual inspections are performed consistent with techniques identified in industry codes and standards such as American Concrete Institute 3-87 (ACI) 349.3 R-96, "Evaluation of Existing Nuclear Safety-Related Concrete Structures," and ANSI/American Society of Civil Engineers (ASCE) 11-90, "Guideline for Structural Condition
 
Assessment of Existing Buildings."
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancement and its
 
justifications to determine whether the AMP, with enhancement, remains adequate to manage
 
the aging effects for which it is credited.
The staff reviewed the program elements (see SER Section 3.0.2.1) for the Masonry Wall Program and its associated bases documents, and compared them to those listed for AMP XI.S5 in the GALL Report for consistency.
Enhancement. In the LRA Section B.2.1.35, the applicant identified an enhancement to makethis AMP consistent with GALL AMP XI.S5. Program procedures will be revised so that
 
structures with masonry walls within the scope of license renewal are clearly identified and the
 
qualification requirements for personnel who perform masonry wall walkdowns within the scope
 
of license renewal are clarified. This enhancement is scheduled to be completed prior to
 
entering the period of extended operation. The applicant concluded that, with the
 
implementation of this enhancement, BFN will ensure continued consistency with the affected
 
program elements.
The staff evaluation of the affected GALL R eport program elements, "Scope of Program"(Element 1), "Parameters Monitored or Inspect ed" (Element 3), and "Detection of Aging Effects"(Element 4), for the acceptability of the exception is as follows:
Scope of Program. The scope includes all masonry walls identified as performing intended functions in accordance with 10 CFR 54.4 Parameters Monitored or Inspected. The primary parameter monitored is wall cracking that could invalidate the evaluation basis.
Detection of Aging Effects. Visual examination of the masonry walls by qualified inspection personnel is sufficient. The frequency of inspection is selected to ensure
 
there is no loss of intended function between inspections. The inspection frequency may
 
vary from wall to wall, depending on the significance of cracking in the evaluation basis.
 
Unreinforced masonry walls that have not been contained by bracing warrant the most
 
frequent inspection, because the development of cracks may invalidate the existing
 
evaluation basis.GALL AMP XI.S5 states that the scope includes all masonry walls identified as performing intended functions in accordance with 10 CFR 54.4. The AMP evaluation states that structures
 
with masonry walls within the scope of license renewal include the BFN reactor buildings, Unit 1
 
and 2 diesel generator building, Unit 3 diesel generator building, Unit 2 turbine building (station
 
blackout (SBO) function), and the intake pumping station. BFN Technical Instruction 0-TI-346
 
will be enhanced to identify that the Unit 1,2, and 3 reactor buildings, Unit 1 and 2 diesel
 
generator building, Unit 3 diesel generator building, Unit 2 turbine building (SBO function), and
 
the intake pumping station are within the scope of license renewal.
3-88 The staff requested that the applicant identify the walls that are within the scope of license renewal. The applicant, as documented in the staff's audit and review report, stated that BFN Technical Instruction 0-TI-346 identifies structures within the scope of license renewal for the Maintenance Rule and will be enhanced to identify structures within the scope of license renewal that require aging management. LCEI-CI-C9 refers to BFN Technical Instruction 0-TI-346 for the detailed listing of structures in the scope of the Maintenance Rule and license renewal. LCEI-CI-C9 requires inspection of masonry walls in structures identified in BFN Technical Instruction 0-TI-346. The staff concurred that, with the enhancement, all the masonry walls that are within the scope of license renewal will be covered by the referenced procedures.GALL AMP XI.S5 also states that visual examination of the masonry walls by qualified inspection personnel is sufficient. The BFN AMP evaluation states that the quality and value of
 
the results obtained from the walkdown assessment activity and the assessment evaluation are dependant on the qualifications and capabilities of the inspection team, as discussed in Chapter
 
7 of ACI 349-3R-96. LCEI-CI-C9 will be enhanced as part of the Structures Monitoring Program
 
enhancements to clarify the qualification requirements for personnel who perform masonry wall
 
walkdowns and evaluations. The staff concurred that this enhancement is consistent with the
 
GALL Report. See the SER Section on Structures Monitoring Program below for information on
 
enhancements to the Structures Monitoring Program.
UFSAR Supplement. In LRA Section A.1.32, the applicant provided the UFSAR supplement for the Masonry Wall Program. The staff reviewed this section and determined that the information
 
in the UFSAR supplement provides an adequate summary description of the program. The staff
 
found this section of the UFSAR supplement met the requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.23  Structures Monitoring Program
 
Summary of Technical Information in the Application. The applicant's Structures Monitoring Program is described in LRA Section B.2.1.36, "Structures Monitoring Program." In the LRA, the
 
applicant stated that this is an existing program. This program is consistent, with enhancements, with GALL AMP XI.S6, "Structures Monitoring Program."
In the LRA Section B.2.1.36, the applicant stated that the Structures Monitoring Program includes periodic inspection and monitoring of the condition of accessible areas of structures.
 
The Structures Monitoring Program implements the requirements of 10 CFR 50.65, "Maintenance Rule." The program incorporates the guidance of RG 1.160, Revision 2, and
 
Nuclear Management and Resources Council 93-01, Revision 2. The Structures Monitoring
 
Program provides inspection guidelines and walkdow n checklists for concrete features, roofs, 3-89 structural steel, masonry walls, seismic gaps, tanks, earthen structures, buried piping, and miscellaneous components such as doors.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancements and
 
justifications to determine whether the AMP, with enhancements, remains adequate to manage
 
the aging effects for which it is credited.
The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the AMP andassociated bases documents, and compared them to those listed for AMP XI.S6 in the GALL
 
Report for consistency.
The staff noted that the basis document does not address protective coating monitoring and maintenance; however, BFN Technical Instruction 0-TI-346 Section 3.3 includes
 
"damaged/degraded coatings" under concrete and structural steel. LCEI-CI-C9 does not
 
address protective coatings in the walkdown procedures. As documented in the staff's audit and
 
review report, the applicant confirmed that protective coatings are not credited to manage aging
 
effects for license renewal.
The staff noted that the program is being expanded to include the inspection of piles and asked the applicant to clarify the types of inspections that will be performed for piles. The applicant
 
stated that piles associated with gate structure Number 3 and the diesel high pressure fire
 
protection (HPFP) house will be visually inspec ted by the Structures Monitoring Program. The portion of the piles exposed to the submerged and outside air environments will be visually
 
inspected by the Structures Monitoring Program. The staff concluded that the AMP would not
 
require any further enhancements to perform the inspections of piles as described by the
 
applicant.
In LRA Section B.2.1.36, the applicant identified three enhancements to make this AMPconsistent with GALL AMP XI.S6.
Enhancement 1. The applicant will enhance procedures implementing the 10 CFR 50.65 Maintenance Rule Program to identify all structures and structural components within the scope
 
of license renewal and all aging effects and associated mechanisms for inspection. The staff
 
evaluation of the affected GALL program el ements "Scope of Program" (Element 1) and "Parameters Monitored or Inspected" (Element 3), for the acceptability of the first enhancement
 
is as follows:
Scope of Program. The applicant specifies the structure/aging effect combinations that are managed by its Structures Monitoring Program.
Parameters Monitored or Inspected. For each structure/aging effect combination, the specific parameters monitored or inspected are selected to ensure that aging
 
degradation leading to loss of intended functions will be detected and the extent of
 
degradation can be determined. Parameters monitored or inspected are to be
 
commensurate with industry codes, standards and guidelines, and are to also consider
 
industry and plant-specific operating experience. Although not required, ACI 349.3R-96
 
and American National Standards Institute (ANSI)/ASCE 11-90 provide an acceptable 3-90 basis for selection of parameters to be monitored or inspected for concrete and steel structural elements and for steel liners, joints, coatings, and waterproofing membranes (if applicable). If necessary for managing settlement and erosion of porous concrete
 
subfoundations, the continued functionality of a site dewatering system is to be
 
monitored. The plant-specific Structures Monitoring Program is to contain sufficient detail
 
on parameters monitored or inspected to conclude that this program attribute is satisfied.
The staff asked the applicant how the structural components and supports that are identified as an enhancement to the scope of the AMP are currently being managed and if a baseline
 
inspection of these structural components and supports will be performed prior to the period of
 
extended operation.
The applicant, as documented in the staff's audit and review report, stated that the identified structural component supports that are to be added to the Structures Monitoring Program are
 
currently being managed by the plant work control procedures and the Corrective Action
 
Program. The applicant further stated that all Structures Monitoring Program enhancements
 
required to document structural components and structural support inspections will receive a
 
baseline inspection prior to the period of extended operation. Structures Monitoring Program
 
baseline inspections are currently required by Section 5.1 of LCEI-CI-C9.
The staff noted that the AMP evaluation states that procedures in BFN Technical Instruction 0-TI-346 and LCEI-CI-C9 will be enhanced to identify all aging effects and associated aging
 
mechanisms to be inspected. Aging effects and mechanisms considered will be consistent with
 
the GALL Report and Section 4 of ACI 349.3R-96. BFN operating experience is considered for
 
selecting each structure/aging effect combination. The aging effects for structures monitored
 
and inspected that will be identified in 0-TI-346 and LCEI-CI-C9 enhancements are documented
 
in the staff's BFN audit and review report.
The staff concurred that this enhancement is consistent with the GALL Report.
 
Enhancement 2. The applicant will enhance LCEI-CI-C9 implementing the 10 CFR 50.65 Maintenance Rule Program sampling approach to include examinations of representative
 
samples of below-grade concrete when excavated for any reason. The staff evaluation of the
 
affected GALL program element "Detection of Aging Effects" (Element 4) for the acceptability of
 
the second enhancement is as follows:
Detection of Aging Effects. For each structure/aging effect combination, the inspection methods, inspection schedule, and inspector qualifications are selected to ensure that aging degradation
 
will be detected and quantified before there is loss of intended functions. Inspection methods, inspection schedule, and inspector qualifications are to be commensurate with industry codes, standards and guidelines, and are to also consider industry and plant-specific operating
 
experience. Although not required, ACI 349.3R-96 and ANSI/ASCE 11-90 provide an
 
acceptable basis for addressing detection of aging effects. The plant-specific Structures
 
Monitoring Program is to contain sufficient detail on detection to conclude that this program
 
attribute is satisfied.
The staff concurred that this enhancement is consistent with the GALL Report.
3-91 Enhancement 3. The staff evaluation of the affected GALL program element "Detection of Aging Effects" (Element 4) for the acceptability of the third enhancement is as follows:
Detection of Aging Effects. (See element description above)
The applicant will enhance LCEI-CI-C9 implementing 10 CFR 50.65, the Maintenance Rule Program, to include the guidance provided in ACI 349.3R-96 Chapter 7 to clarify the "suitably
 
knowledgeable or trained" inspector qualifications to "training and proficiency demonstration of
 
inspectors for structural aging effects and long term performance issues." The procedures will
 
also be clarified to identify the "responsible engineer" as the "Structures Monitoring Program
 
engineer" to avoid confusion with industry guidance. LCEI-CI-C9 will also be clarified to identify
 
the "responsible engineer" as the "Structures Monitoring Program engineer" to avoid confusion
 
with industry guidance.
The staff had a follow up question in a May 4, 2005, teleconference regarding evaluation of inspection personnel qualification based on industry guidance ACI 349.3R-96 as stated in the
 
Structures Monitoring Program. The staff stated that this industry guidance alone will not be
 
adequate to qualify the inspectors for the examination of steel supports for the Structures
 
Monitoring Program. The staff requested that the applicant reevaluate the program element from previous staff positions and submit the description for staff review. The applicant
 
responded to the staff's question and committed to manage the aging effects of Class MC supports under ASME Code Section XI Subsection IWF. In its response to a follow up to
 
RAI B.2.1.33-1, the applicant also agreed to include the inspector's qualification in accordance with the requirements of ASME Code Section XI Subsection IWF and not per the BFN
 
Structures Monitoring Program. In its response to a follow up to RAI B.2.1.33-1,by  letter dated
 
May 31, 2005, the applicant responded to the staff's question and committed to manage the aging effects of Class MC supports under ASME Code Section XI Subsection IWF. The
 
applicant also agreed to include the inspector's qualification in accordance with the requirements of ASME Code Section XI Subsection IWF and not per the BFN Structures
 
Monitoring Program.
Subject to the applicant's complying by submitting this resolution of this confirmatory item, the staff concurred that this enhancement is consistent with the GALL Report.
Operating Experience. In LRA Section B.2.1.36, the applicant stated that plant-specific performance results of the Structures Monitoring Program had been reviewed. The program has
 
been shown to be effective in managing aging effects of structural features and components.
 
Examples of the plant-specific operating experi ence issues are documented in the staff's BFN audit and review report and were determined to be insignificant with respect to maintaining
 
structural adequacy. Defects were identified as PERs and dispositioned in accordance with the
 
Maintenance Rule Program by methods such as repair, cause determination, cause mitigation, or monitoring to ensure the continued availability of the function.
In addition to the operating experience discussed in the AMP, the AMP evaluation stated that a baseline inspection for the Structures Monitoring Program was established in 1997 and is
 
documented in calculation CDQO-303-970086. Defect evaluations performed since the baseline
 
inspection and inspection results from the 2002 Structures Monitoring Program are documented
 
in calculation CDQO-303-2003-0260. Observed aging effects for structures within the scope of 3-92 license renewal were evaluated not to significantly challenge the ability of structures to meet design requirements or perform their intended function.
During the onsite audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing basis. The
 
staff concluded there is reasonable assurance that operating experience will continue to be
 
reviewed in the future to ensure that the effects of aging will be adequately managed, consistent
 
with the guidance in the GALL Report.
UFSAR Supplement. In LRA Section A.1.33, the applicant provided the UFSAR supplement for the Structures Monitoring Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancements and
 
confirmed that the implementation of t he enhancements prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which
 
it was compared. The staff concluded that the applicant had demonstrated that the effects of
 
aging will be adequately managed so that the intended functions will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff
 
also reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.2.24  Inspection of Water-Controlled Structures Program Summary of Technical Information in the Application. The applicant's Inspection of Water-Controlled Structures Program is described in LRA Section B.2.1.37, "Inspection of
 
Water-Controlled Structures Program." In the LRA, the applicant stated that this is an existing program. This program is consistent, with enhancements, with GALL AMP XI.S7, "RG 1.127, Inspection of Water-Controlled Structures Associated with Nuclear Power Plants."
In LRA Section B.2.1.37, the applicant stated that the Inspection of Water-control Structures Program manages age-related deterioration, degradation due to extreme environmental conditions, and the effects of natural phenomena that may affect water-control structures. BFN
 
is not committed to RG 1.127, "Inspection of Water-Control Structures Associated with Nuclear
 
Power Plants," but has a program in place that is consistent with the elements of RG 1.127, as
 
evaluated in the GALL Report. The program is included in the Structures Monitoring Program (B.2.1.36), which implements the structures monitoring requirements of 10 CFR 50.65
 
"Maintenance Rule." The Inspection of Water-control Structures Program includes in-service
 
inspection and surveillance activities for dams, slopes, canals, and other water-control
 
structures.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancements and its 3-93 justifications to determine whether the AMP, with enhancements, remains adequate to manage the aging effects for which it is credited.
The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the AMP, associated bases documents, and the implement ing documents, and compared them to thoselisted for AMP XI.S7 in the GALL Report for consistency. The staff did not request any
 
clarifications or additional information from the applicant for this AMP.
Enhancement 1. The applicant will enhance program documents to ensure that required structures and structural components within the scope of license renewal are identified.
 
Although the LRA indicates that this enhancement affects GALL Report program element
 
"Parameters Monitored or Inspected" (Element 3), the staff noted that the description of the
 
enhancement in the LRA more appropriately perta ins to GALL Report program element, "Scope of Program" (Element 1). Therefore, the staff evaluated this enhancement against the GALL
 
Report element as follows.
Scope of Program - RG 1.127 applies to water-control structures associated with emergency cooling water systems or flood protection of nuclear power plants. The
 
water-control structures included in the RG 1.127 program are concrete structures;
 
embankment structures; spillway structures and outlet works; reservoirs; cooling water channels and canals, and intake and discharge structures; and safety and performance
 
instrumentation.
The applicant's AMP basis document (AMP evaluation) states that the scope of the Inspection of Water-Controlled Structures Program includes the following list of structures identified in BFN
 
Technical Instruction 0-TI-346, Attachment 38:
* intake pumping station
* gate structure No. 3
* intake channel
* north bank of cool water channel east of gate structure Number 2
* south dike of cool water channel between gate structure Number 2 and 3 (only that portion of the south dike over the RHRSW discharge piping)
Procedures, 0-TI-346 and LCEI-CI-C9, will be enhanced to identify all structures and structural components within the scope of license r enewal. Component enhancements will expand the walkdown checklist of structural steel components to include items such as anchors, bolts, fasteners, and other miscellaneous steel and non-ferrous materials. Component enhancements
 
will also require expanding the checklist for seismic gaps to include seals and caulking that are
 
used to prevent flooding. Component enhancements will be based on the list of structural
 
components within the scope of license renewal in the AMR.
BFN Technical Instruction 0-TI-246 augments LCEI-CI-C9 in that it provides the inspection requirements for water holding or transporting earthen structures. The scope of 0-TI-246 is
 
identified in Appendix A and includes the intake channel, north bank of cool water channel east
 
of gate structure Number 2, and the south dike of cool water channel between gate structure
 
Numbers 2 and 3. Appendix A of BFN Technical Instruction 0-TI-246 will be enhanced to
 
indicate that the intake channel, north bank of cool water channel east of gate structure Number
 
2, and south dike of cool water channel between gate structure Numbers 2 and 3 (only that 3-94 portion of the south dike over the RHRSW discharge piping) are within the scope of license renewal and require aging management. The staff concurred that this enhancement is
 
consistent with the GALL Report.
Parameters Monitored or Inspected. RG 1.127 identifies the parameters to be monitored and inspected for water-control structures. The parameters vary depending on the
 
particular structure. Parameters to be monitored and inspected for concrete structures
 
include cracking, movements (e.g., settlement, heaving, deflection), conditions at
 
junctions with abutments and embankments, erosion, cavitation, seepage, and leakage.
 
Parameters to be monitored and inspected for earthen embankment structures include
 
settlement, depressions, sink holes, slope stability (e.g., irregularities in alignment and
 
variances from originally constructed slopes), seepage, proper functioning of drainage
 
systems, and degradation of slope protection features. Further details of parameters to
 
be monitored and inspected for these and other water-control structures are specified in
 
Section C.2 of RG 1.127.
The applicant's AMP basis document states that 0-TI-346 and LCE-CI-C9 provide for monitoring of concrete structures, structural steel, non-ferrous components, and earthen structures. BFN
 
Technical Instruction 0-TI-246 augments LCEI-CI-C9 and provides the inspection requirements for water holding or transporting earthen structures such as ponds, channels, and associated
 
dikes. BFN Technical Instruction 0-TI-346 and LCEI-CI-C9 will be enhanced to identify aging
 
effects and associated aging mechanisms to be inspected, consistent with GALL Chapter III for
 
Group 6 structures, Section 4 of ACI 349-3R-96, and the EPRI Structural Tools document. The
 
aging effects identified in the 0-TI-346 and LCEI-CI-C9 enhancements are included as
 
enhancements to the Structures Monitoring Program. The staff concurred that these
 
enhancements are consistent with the GALL Report.
Enhancement 2. The applicant's program will enhance the documents to include special inspections following the occurrence of large floods, earthquakes, tornadoes, and intense
 
rainfall. The staff evaluation of the affected GALL Report program element "Detection of Aging
 
Effects" (Element 4) for the acceptability of the second enhancement is as follows:
Detection of Aging Effects. Visual inspections are primarily used to detect degradation of water-control structures. In some cases, instruments have been installed to measure the
 
behavior of water-control structures. RG 1.127 indicates that the available records and
 
readings of installed instruments are to be reviewed to detect any unusual performance
 
or distress that may be indicative of degradation. RG 1.127 describes periodic
 
inspections, to be performed at least once every fi ve years. Similar intervals of five years are specified in ACI 349.3R for inspection of structures continually exposed to fluids or
 
retaining fluids. Such intervals have been shown to be adequate to detect degradation of
 
water-control structures before they have a significant effect on plant safety. RG 1.127
 
also describes special inspections immediately following the occurrence of significant
 
natural phenomena, such as large floods, earthquakes, hurricanes, tornadoes, and
 
intense local rainfalls.
The applicant's AMP basis document states that 0-TI-246 Section 7.2 specifies a special inspection of water-holding or water-transporting earthen structures within 30 days following
 
extreme environment or natural phenomena. LCEI-CI-C9 will be enhanced to include a special inspection for the intake pumping station and gate structure No. 3, following the occurrence of 3-95 large floods, earthquakes, tornadoes, and intense rainfall. The staff concurred that this enhancement is consistent with the GALL Report.
Operating Experience. In LRA Section B.2.1.37, the applicant stated that plant-specific performance results of the inspection of the Water-Control Structures Program, as implemented
 
by the Structures Monitoring Program to meet the requirements of 10 CFR 50.65, were
 
reviewed. The program has been shown to be effective in managing aging effects of structural
 
features and components. The applicant identified two examples of plant-specific operating
 
experience.
* Intake pumping station: very minor concrete surface cracks and platform grating clipped
* Gate structure No. 3: very minor concrete surface cracks and spalling Neither was considered significant enough to affect the function of a structure.
 
In addition to the operating experience discussed in the LRA, the AMP evaluation stated that a review of the operating experience for water-control structures within the scope of license
 
renewal did not identify any PERs (SPP-3.1 Corrective Action Program) related to RG 1.127, "Inspection of Water-Control Structures Associated with Nuclear Power Plants." A baseline
 
inspection for the Structures Monitoring Program was established in 1997 and is documented in
 
Calculation CDQO-303-970086. Defect evaluations performed since the baseline inspection and
 
inspection results from the 2002 Structures Monitoring Program are documented in calculation
 
CDQO-303-2003-0260. The Structures Monitoring Program inspections noted the above aging
 
effects and associated defect evaluations for water-control structures within the scope of license
 
renewal. Observed aging effects for water-control structures in the scope of license renewal
 
were evaluated not to significantly challenge the ability of water-control structures to meet
 
design requirements or perform their intended function.
During the onsite audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing basis. The
 
staff concluded there is reasonable assurance that operating experience will continue to be
 
reviewed in the future to ensure that the effects of aging will be adequately managed.
The staff found that the applicant had adequately considered operating experience, consistent with the guidance in the GALL Report.
UFSAR Supplement. In LRA Section A.1.34, the applicant provided the UFSAR supplement for the Inspection of Water-Controlled Structures Program. The staff reviewed this section and
 
determined that the information in the UFSAR supplement provides an adequate summary
 
description of the program. The staff found this section of the UFSAR supplement met the
 
requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancements and
 
confirmed that the implementation of t he enhancements prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which
 
it was compared. The staff concluded that the applicant had demonstrated that the effects of
 
aging will be adequately managed so that the intended functions will be maintained consistent 3-96 with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.25  Environmental Qualification Program
 
Summary of Technical Information in the Application. The applicant's EQ Program is described in LRA Section B.3.1, "Environmental Qualificat ion Program." In the LRA, the applicant stated that this is an existing program. This program is consistent, with enhancement, with GALL AMP X.E1, "Environmental Qualification of Electric Components."
LRA Section 4.4 affirms the applicant's compliance with generic safety issue (GSI)-168,"Environmental Qualification of Low-Voltage In strumentation and Control Cables," and follow-up NRC Regulatory Issue Summary 2003-9, "Environmental Qualification of Low-Voltage
 
Instrumentation and Control Cables," May 2, 2003, which the GALL Report cites as a currently
 
open generic issue with ongoing research.
The applicant follows nuclear station EQ requirements in 10 CFR 50.49. The requirements are that each licensed facility establish an EQ Program to demonstrate that electrical components
 
located in harsh plant environments are qualified to perform their safety function in those harsh
 
environments while withstanding the effects of inservice aging. The effects of significant aging
 
mechanisms must be addressed as part of EQ.
In LRA Section B.3.1, the applicant stated that the EQ Program manages component thermal, radiation, and cyclical aging effects through the use of aging evaluations based on
 
10 CFR 50.49(f) qualification methods. As required by 10 CFR 50.49, EQ components not
 
qualified for the current license term are to be refurbished, replaced, or have their qualification
 
extended prior to reaching the aging limits established in the evaluation. Aging evaluations for
 
EQ components are considered TLAAs for license renewal. The staff's evaluation is included in
 
SER Section 4 (see SER Section 4.4).
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancement and its
 
justifications to determine whether the AMP, with enhancement, remains adequate to manage
 
the aging effects for which it is credited.
In LRA Section B.3.1, the applicant stated that the EQ Program is consistent with GALLAMP X.E1. The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the AMP and associated bases documents, and compared them to those listed for GALL AMP X.E1
 
for consistency. The staff identified three differences in the EQ component reanalysis attributes, as discussed below.
In the AMP basis document, the applicant stated that the analytical models used in the re-analysis of an aging evaluation will, in most cases, be the same as those applied during the initial qualification. However, the description of GALL AMP X.E1 states that the analytical
 
models used in the re-analysis of an aging evaluation should be the same as those previously
 
applied during the prior evaluation. The staff asked under what circumstances the analytical 3-97 models used in the re-analysis of an aging evaluation would not be the same as those applied during the initial qualification.
The applicant stated, as documented in the staff's BFN audit and review report, that BFN will use the same analytical methods used in the original EQ evaluations. If a different method is
 
used, the basis for using the method will be documented in the EQ package. The staff found
 
this acceptable.The staff noted that the LRA does not address the recommendation in GALL AMP X.E1 that a representative number of temperature measurem ents be conservatively evaluated to establish the temperatures used in an aging evaluation.
The applicant, as documented in the staff's audit and review report, stated that BFN currently has no plans to monitor temperatures to extend the qualified life of EQ components. If the need
 
arises, a representative number of temperatur e measurements will be used to establish the temperature used in the aging analysis. The collection methodology and the data collected will
 
be documented as part of the EQ package. The staff found this acceptable.The staff also noted that the LRA does not address the recommendation in GALL AMP X.E1 that any changes to material activation energy values as part of a re-analysis are to be justified
 
on a plant-specific basis.
The applicant stated, as documented in the staff's audit and review report, that BFN currently has no plans to change activation energies as part of the evaluation to extend the life of EQ
 
components. If during the evaluation process an activation energy is changed, the basis for
 
changing the value will be documented in the EQ package. The staff found this acceptable.
Enhancement. In LRA Section B.3.1, the applicant identified one enhancement to make thisAMP consistent with AMP X.E1 in the GA LL Report. The EQ Program will be implemented on Unit 1. The enhancement is scheduled for completion prior to Unit 1 re-start from its current
 
extended outage. The staff found this enhancement acceptable since it will make the applicant's
 
program consistent for all three units.
Operating Experience. In LRA Section B.3.1, the applicant stated that operating experience is a vital consideration in maintaining the current EQ Program and in modifying qualification bases
 
and conclusions, including qualified life. The engineering, technical, and programmatic
 
requirements and processes followed in establishing and maintaining the EQ Program include a
 
review of licensing, industry, and other generic documentation for EQ applications and
 
involvement in various utility groups.
Further, industry operating experience was incorporated into the license renewal process through a review of industry documents to identify aging effects and mechanisms that could
 
challenge the intended function of SSCs within the scope of license renewal. A review of
 
plant-specific operating experience was also performed to identify plant-specific aging effects
 
and none were found.
During the onsite audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing basis. The 3-98 staff concluded there is reasonable assurance that operating experience will continue to be reviewed in the future to ensure that the effects of aging will be adequately managed.
The staff found that the applicant had adequately considered operating experience, consistent with the guidance in the GALL Report.
UFSAR Supplement. In LRA Section A.1.35, the applicant provided the UFSAR supplement for the EQ Program. The staff reviewed this section and determined that the information in the UFSAR supplement provides an adequate summary description of the program. The staff found this section of the UFSAR supplement met the requirements of 10 CFR 54.21(d).
 
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.26  Fatigue Monitoring Program
 
Summary of Technical Information in the Application. The applicant's Fatigue Monitoring Program is described in LRA Section B.3.2, "Fatigue Monitoring Program." In the LRA, the
 
applicant stated that this is an existing program. This program is consistent, with enhancements, with GALL AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary."
In the LRA, the applicant stated that the Fatigue Monitoring Program is used for management of metal fatigue of select components in the reactor coolant pressure boundary and primary
 
containment. The fatigue monitoring program prov ides for monitoring fatigue stress cycles to ensure that the design fatigue usage factor limit is not exceeded.
Aging evaluations for fatigue monitored components are considered TLAAs for license renewal.
The staff's evaluation is included in SER Section 4 (see SER Section 4.3).
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are documented in the
 
BFN audit and review report. Furthermore, the staff reviewed the enhancements and its
 
justifications to determine whether the AMP, with enhancements, remains adequate to manage
 
the aging effects for which it is credited.
The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the AMP basisdocument and compared them to those listed for AMP X.M1 in the GALL Report for
 
consistency. The staff concluded that the elements of the Fatigue Monitoring Program are
 
consistent with the elements of the AMP in the GALL Report.
3-99 The staff during the GALL consistency audit questioned how the current (starting) fatigue cumulative usage factor (CUF) will be calculated for locations to be added to the scope of the
 
Fatigue Monitoring Program, as identified under program enhancements. This is needed as
 
initial input to either a manual or automated tracking system.
The applicant described two alternate fatigue monitoring approaches, (1) stress-based fatigue (SBF) and (2) cycle-based fatigue (CBF), each with a different procedure, used for calculating the starting CUF. The staff reviewed the two procedures and concluded that the procedure to be
 
utilized with CBF, based on plant records of experienced transients, is reasonable and
 
conservative, while the procedure to be utilized with SBF, based on linear projection, is
 
potentially nonconservative. The staff asked the applicant to provide its technical basis for
 
concluding that the procedure to be utilized with SBF is reasonable and conservative, especially
 
in light of the industry operating experience cited by the applicant (i.e., "concerns that early-life
 
operating experience, at some units, had caused CUF values to increase at a faster rate than
 
anticipated in the original plant design").
The applicant, as documented in the staff's audit and review report, stated that the same procedure, based on plant records of experienced transients, will be used to calculate the
 
starting CUF for both the SBF and CBF fatigue monitoring approaches. Detailed results of the
 
staff's onsite audits are documented in "Audi t Report for Plant Aging Management Programs and Aging Management Reviews - Browns Ferry Nuclear Plant Units 1, 2, and 3," dated
 
April 26, 2005. The staff found this acceptable.
Enhancement. In LRA Section B.3.2, the applicant identified an enhancement to make this AMPconsistent with AMP X.M1 in the GALL Report. The staff evaluation of the affected GALL
 
program element, "Scope of Program" (Element 1), for the acceptability of the enhancement is as follows:
Scope of Program. The program includes preventive measures to mitigate fatigue cracking of metal components of the reactor coolant pressure boundary caused by
 
anticipated cyclic strains in the material.
The applicant will, prior to the period of extended operation, enhance the Fatigue Monitoring Program by using the EPRI-licensed FatiguePro cycle-counting and fatigue-usage tracking
 
computer program. This program calculates stress cycles and resulting CUF values from
 
operating cycles. These calculations will be automated and performed periodically based on information downloads from the plant's in strumentation computers. The enhancements will include expansion of the program coverage to include selected reactor vessel locations as
 
specified in LRA Table 4.3.1.1; the locations identified by NUREG/CR-6260 for environmental
 
fatigue evaluation, as discussed in LRA Section 4.3.4 and in accordance with the GALL Report Section X.M1; and fatigue monitoring of the suppression chamber and suppression chamber
 
vents, including the vent headers and downcomers, as specified in LRA Section 4.6.1.The staff found that the enhanced program will be consistent with GALL AMP X.M1.
 
Operating Experience. In the LRA, the applicant stated that since the original licensing of BFN, the industry has sponsored the development of the EPRI-licensed FatiguePro computer
 
program. This action was taken in response to staff concerns that early-life operating
 
experience at some units had caused CUF values to increase at a faster rate than anticipated in 3-100 the original plant design. This program provides for the incorporation of operating experience, and is designed to ensure that the CUF values do not exceed acceptable limits in the remainder
 
of a unit's operating life.
The staff found there is reasonable assurance that the Fatigue Monitoring Program will be effective in monitoring fatigue usage factors at critical locations, on the basis that the program is consistent with GALL AMP X.M1.
During the onsite audit, the staff noted that the applicant incorporates internal and external plant operating experience issues into the plant Corrective Action Program on a continuing basis. The
 
staff concluded there is reasonable assurance that operating experience will continue to be
 
reviewed in the future to ensure that the effects of aging will be adequately managed.
UFSAR Supplement. In LRA Section A.1.36, the applicant provided the UFSAR supplement for the Fatigue Monitoring Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review and audit of the applicant's program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent with the GALL Report. In addition, the staff reviewed the enhancement and
 
confirmed that the implementation of the enhanc ement prior to the period of extended operation would result in the existing AMP being consistent with the GALL Report AMP to which it was
 
compared. The staff concluded that the applicant had demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).3.0.3.3  AMPs That Are Not Consistent with or Not Addressed in the GALL Report In LRA Appendix B, the applicant identified the following plant-specific AMPs:
* Systems Monitoring Program (B.2.1.39)
* Bus Inspection Program (B.2.1.40)
* Diesel Starting Air Program (B.2.1.41)
* Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program (B.2.1.13)
For AMPs that are not consistent with or not addressed by the GALL Report, the staff performed a complete review of the AMPs to determine if they were adequate to monitor or manage aging.
 
The staff's review of these plant-specific AMPs is documented in the following sections of this
 
SER.3.0.3.3.1  Systems Monitoring Program
 
Summary of Technical Information in the Application. The applicant's Systems Monitoring Program is described in LRA Section B.2.1.39, "Systems Monitoring Program." In the LRA, the
 
applicant stated that this is an existing plant-specific program.
3-101 Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in LRA Section B.2.1.39, regarding the applicant's demonstration of the Systems
 
Monitoring Program to ensure that the effects of aging, as discussed above, will be adequately
 
managed so that the intended functions will be maintained consistent with the CLB throughout
 
the period of extended operation.
The staff reviewed the Systems Monitoring Pr ogram against the AMP elements found in the SRP-LR Section A.1.2.3 and SRP-LR Table A.1-1, and focused on how the program manages
 
aging effects through the effective incorporation of 10 elements (i.e., program scope, preventive actions, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and
 
operating experience).
The applicant indicated that the corrective actions, confirmation process, and administrative controls are part of the site-controlled quality assurance program. The staff's evaluation of the
 
quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements
 
are discussed below.  (1)Scope of Program - In LRA Section B.2.1.39, the applicant stated that the program requirements are for visual inspections to identify material condition (i.e., loss of
 
material, corrosion etc) of surfaces and components within the scope of license renewal
 
as identified in the AMRs. The staff found the scope of the program to be comprehensive
 
and acceptable because it includes the components that credit this program, as
 
identified in the AMR tables.
The staff confirmed that the scope of the program element satisfies the criterion defined in SRP-LR Section A.1.2.3.1. The staff concluded that this program attribute is
 
acceptable.    (2)Preventive Actions - In LRA Section B.2.1.39, the applicant stated that the Systems Monitoring Program is a condition monitori ng program; thus, there are no preventive actions. The staff concurred with this assessment and does not identify the need for any
 
preventive actions associated with this program.
The staff confirmed that the preventive actions program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2. The staff concluded that this program attribute is
 
acceptable.  (3)Parameters Monitored or Inspected - The LRA states that the Systems Monitoring Program includes visual inspections to identif y material condition (i.e., loss of material, corrosion, etc.) of surfaces of systems and components prior to the loss of their intended
 
function. The staff found that the parameters monitored or inspected will provide
 
symptomatic evidence of potential degradation and, therefore, are acceptable.
The staff confirmed that the parameters monitored or inspected program element satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff concluded that this
 
program attribute is acceptable.
3-102  (4)Detection of Aging Effects - In LRA Section B.2.1.39, the applicant stated that the program includes visual inspections to identif y material condition (i.e., loss of material, corrosion, etc.) of surfaces of systems and components prior to the loss of their intended
 
function. The system visual inspections are performed on a periodic basis and provide
 
for data collection on systems and components for monitoring and trending to ensure
 
timely detection of aging effects. Visual inspection is a continuous process with results
 
periodically reported in system health reports.
The staff's review of LRA Section B.2.1.39 identified an area in which additional information was necessary to complete the review of the applicant's program element.
 
The applicant responded to the staff's RAI as discussed below.
In RAI B.2.1.39-1, dated October 12, 2004, the staff asked the applicant if a sampling approach is used and, if so, to justify that the sample size is adequate. The applicant
 
was also requested to clarify how external surfaces of systems that are covered by
 
insulation, or are located in normally inaccessible areas, are to be visually inspected.
 
Further, the applicant was requested to clarify how elastomer degradation would be
 
detected by visual inspection and to clarify how external surface inspections would
 
detect internal aging effects caused by exposure to treated water for the flexible
 
connectors in the diesel generator system.
In its response by letter dated November 3, 2004, the applicant clarified that visual inspection is performed on accessible components during system walkdowns and that
 
visual inspections should encompass all or part of the total accessible system, such that
 
the entire system is covered over time. The applicant also clarified that the portions of
 
the system that are inaccessible during power operation should be walked down during
 
the refueling outages or forced outages. In regard to flexible connectors in the diesel
 
generator system, the applicant explained that the AMP identified by the LRA is incorrect and that the internal aging effects are managed by the One-Time Inspection Program
 
and the external effects are managed by the Systems Monitoring Program.
The staff found the applicant's response acceptable on the basis that there is reasonable assurance that visual inspections of accessible surfaces of systems and
 
components, combined with inspections during outages, are capable of detecting the
 
aging effects that are covered by this program. The use of visual inspections to detect
 
external degradation is consistent with industry practice.
The staff confirmed that the detection of aging effects program element satisfies the criterion defined in SRP-LR Section A.1.2.3.4. The staff concluded that this program
 
attribute is acceptable.    (5)Monitoring and Trending - In LRA Section B.2.1.39, the applicant stated that the inspected systems and components are moni tored, trended, and documented by the use of System Health Reports, the Corre ctive Action Program, and the Corrective Maintenance Program. The staff found that the overall monitoring and trending proposed
 
by the applicant are acceptable because there is reasonable assurance that an effective
 
walkdown program combined with the Corrective Action Program and the Corrective
 
Maintenance Program will effectively manage the applicable aging effects.
3-103 The staff confirmed that the monitoring and trending program element satisfies the criteria defined in SRP-LR Section A.1.2.3.5. The staff concluded that this program
 
attribute is acceptable.    (6)Acceptance Criteria - In LRA Section B.2.1.39, the applicant stated that during a system or component visual inspection, system engineers use their knowledge of the UFSAR, TSs, design basis documents, operating experience, and the plant operating, technical, and maintenance procedures to evaluate system physical attributes and operational
 
characteristics. In RAI B.2.1.39-1, the applicant was also requested to clarify the
 
acceptance criteria applied in the inspection or evaluation of degradation. In its
 
response, the applicant provided guidance to the system engineer, which is that there
 
should be no evidence of steam or water leakage and system wastage, and that surface
 
condition of welds appear satisfactory. The staff found that a detailed look at the material
 
condition and degraded components by a knowledgeable system engineer , combined with effective corrective actions, are a reasonable approach to detect and evaluate
 
degradation in applying design basis acceptance criteria.
The staff confirmed that the acceptance criter ia program element satisfies the criteria defined in SRP-LR Section A.1.2.3.6. The staff concluded that this program attribute is
 
acceptable.    (10)Operating Experience - In LRA Section B.2.1.39, the applicant stated that the Systems Monitoring Program produces system health r eports, which provide a review of systems and components' operating experience. The LRA also states that the effectiveness of
 
the corrective actions have been evaluated and documented in system health reports. In RAI B.2.1.39-1, the staff further asked the applicant to identify specific operating
 
experience that provides objective evidence to support the conclusion that the Systems Monitoring Program is effective in managing aging effects on the external surfaces of systems and components within the scope of the program. In the response dated, November 3, 2004, the applicant clarified that the Systems Monitoring Program, through
 
the use of PERs and WOs, tracks and trends corrective actions and provides objective
 
evidence to support a determination that the effects of aging will be adequately managed
 
so that the systems and components intended function will be maintained during the
 
period of extended operation. The staff found that there is reasonable assurance that the
 
applicant's use of system health reports combined with PERs and WOs should provide
 
objective evidence to support the conclusion that the program will adequately manage
 
the aging effects in the systems and components that credit this program. Therefore, the staff's concerns described in RAI.2.1.39-1 are resolved.
The staff confirmed that the operating experi ence program element satisfies the criteria defined in SRP-LR Section A.1.2.3.10. The staff concluded that this program attribute is
 
acceptable.
UFSAR Supplement. In LRA Section A.2.1, the applicant provided the UFSAR supplement for the Systems Monitoring Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
3-104 Conclusion. On the basis of its review, RAI response, and audit of the applicant's program, the staff concluded that the applicant had demonstrated that the effects of aging will be adequately
 
managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplements for this AMP and found that they provide an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3.0.3.3.2  Bus Inspection Program
 
Summary of Technical Information in the Application. The applicant's Bus Inspection Program is described in LRA Section B.2.1.40, "Bus Inspection Program." In the LRA, the applicant stated
 
that this is a new plant-specific program.
In the LRA, the applicant stated that the Bus Inspection Program will be initiated prior to the period of extended operation. This commitment is identified on the applicant's license renewal
 
commitment list as Item 38. The applicant stated that this is a non-GALL program and will
 
provide reasonable assurance that the bus ducts will continue to perform their intended function
 
consistent with the CLB through the period of extended operation.
The Bus Inspection Program will provide reasonable assurance that the intended functions of isolated and nonsegregated phase bus will be maintained consistent with the CLB through the
 
period of extended operation. It will manage nonsegregated phase bus insulation exposed to
 
adverse localized environments caused by heat in the presence of oxygen and loosening the fastening hardware associated with isolated and non-segregated phase bus due to cyclic
 
loading resulting in thermal expansion and contraction. The program will also include inspection
 
of the bus enclosure.
This program will manage all portions of isolated and non-segregated phase bus associated with the unit station service transformers, main transformers, and common station service transformers within the scope of license renewal.
The aging mechanisms managed by this program include degradation of the nonsegregated phase bus insulation caused by heat in the presence of oxygen and cyclic loading of isolated
 
and non-segregated phase bus causing thermal expansion and contraction of the bus, which
 
could loosen the bus connection fastening hardware. Any one of these conditions could lead to
 
a failure, preventing the phase bus from performing its intended function.
The program will be performed in conjunction with routine maintenance activities. The program will include visual inspection and electrical testing of in-scope, non-segregated phase bus for
 
evidence of loosened bolted bus connections and damage to bus insulation. The program will
 
also include visual inspection and electrical testing of in-scope isolated phase bus for evidence
 
of loosened bolted bus connections and visual inspection of the in-scope isolated and
 
non-segregated phase bus enclosure for excessive dust build up, evidence of water intrusion, and debris.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in LRA Section B.2.1.40, regarding the applicant's demonstration of the Bus Inspection
 
Program to ensure that the effects of aging will be adequately managed so that the intended 3-105 functions will be maintained consistent with the CLB throughout the period of extended operation.
The staff reviewed the Bus Inspection Program against the AMP elements found in SRP-LR Section A.1.2.3 and SRP-LR Table A.1-1, and focused on how the program manages aging
 
effects through the effective incorporation of 10 elements (i.e., program scope, preventive actions, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and
 
operating experience).
The applicant indicated that the corrective actions, confirmation process, and administrative controls are part of the site-controlled quality assurance program. The staff's evaluation of the
 
quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements
 
are discussed below.
The staff's review of LRA Section B.2.1.40 identified an area in which additional information was necessary to complete the review of the applicant's program elements. The applicant responded
 
to the staff's RAI, as discussed below.
In RAI 3.6-4, dated November 4, 2004, the staff requested the applicant to provide additional information regarding details of the program elements of the AMP.
In its response, by letter December 9, 2004, the applicant provided the augmented details for the seven program elements as follows.  (1)Scope of Program - This program applies to the isolated phase bus duct, as well as the non-segregated bus ducts associated with the unit station service transformers, main
 
transformers, and common station service transformers within the scope of license
 
renewal.The staff confirmed that the scope of the program element satisfies the criterion defined in SRP-LR Section A.1.2.3.1. The staff concluded that this program attribute is
 
acceptable.    (2)Preventive Actions - In LRA Section B.2.1.40, the applicant stated that the Bus Inspection Program will be a condition monitoring program. No actions will be taken as
 
part of this program to prevent or mitigate aging degradation. This is acceptable because
 
the staff found no need for such actions.
The staff confirmed that the preventive actions program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2. The staff concluded that this program attribute is
 
acceptable.  (3)Parameters Monitored or Inspected - In LRA Section B.2.1.40, the applicant stated that the bus insulation will be visually inspected for embrittlement, cracking, melting, discoloration, or other damage. In addition, the bus insulation will be tested using a
 
proven test for detecting deterioration of the insulation system, such as insulation
 
resistance, or other testing that is state-of-the-art at the time the test is performed. The
 
specific type of test performed will be determined prior to the initial test. Bolted bus 3-106 connections will be visually inspected for evidence of burning or heat-up on tape connections, loose connections or arcing on boot-type cover sleeves, and evidence of
 
tracking, corrosion, or ground faults on uninsulated connections. In addition, the bolted
 
bus connections will be tested using a proven test for detecting deterioration of the
 
bolted connection, such as micro-ohm resistance or other testing that is state-of-the-art
 
at the time the test is performed. The specific type of test performed will be determined
 
prior to the initial test.
The applicant stated that the bus enclosure internal will be visually inspected for foreign debris, excessive dust build-up, and evidence of water intrusion. Additionally, the internal
 
bus supports and insulators that are visible from the inspection hatches will be inspected
 
for structural integrity and signs of cracks.
The staff found that the visual inspection of bus ducts, bus bar, and internal bus supports will provide an indication of aging effects. Additionally, testing of bolted
 
connections and insulation system will provide assurance that bus ducts are not
 
exposed to excessive ohmic or ambient heating.
The staff confirmed that the parameters monitored or inspected program element satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff concluded that this
 
program attribute is acceptable.    (4)Detection of Aging Effects - In LRA Section B.2.1.40, the applicant stated that the detection of aging effects will commence prior to the expiration of the current 40-year
 
license for each unit, and will be conducted at least once every 10 years thereafter
 
throughout the period of extended operation. The staff found that the 10-year inspection
 
frequency is an adequate period to preclude failure of bus ducts because industry
 
experience has shown that the aging degradation is a slow process.
The staff confirmed that the detection of aging effects program element satisfies the criterion defined in SRP-LR Section A.1.2.3.4. The staff concluded that this program
 
attribute is acceptable.    (5)Monitoring and Trending - In LRA Section B.2.1.40, the applicant stated that trending is not a required attribute of this program.
The staff confirmed that the monitoring and trending program element satisfies the criteria defined in SRP-LR Section A.1.2.3.5. The staff concluded that this program
 
attribute is acceptable.  (6)Acceptance Criteria - In LRA Section B.2.1.40, the applicant stated that phase bus insulation must be free of embrittlement, cracking, melting, discoloration, or other
 
damage; and it must pass the acceptance criteria established for the test being
 
performed. The bus enclosure will be free of unacceptable indications of cracks, corrosion, foreign debris, excessive dust build-up, and evidence of water intrusion.
 
Bolted bus connection splice shall not have any of the following signs:
* For taped connections: tape burning/heating-up, tape cracking, corona effects, or other damage 3-107
* For boot type cover splices: "as found" loose connections and arcing damage
* For uninsulated connections: evidence of tracking, corrosion, or ground faults It shall also pass the acceptance criteria established for the test being performed.
 
The staff found this to be acceptable since the acceptance criteria are based on the inspections and test acceptance criteria.
The staff confirmed that the acceptance criter ia program element satisfies the criteria defined in SRP-LR Section A.1.2.3.6. The staff concluded that this program attribute is
 
acceptable.    (10)Operating Experience - In LRA Section B.2.1.40, the applicant stated that this is a new AMP; therefore, no operating experience exists. In response to the staff's RAI 3.6-4, the
 
applicant stated that both industry and plant-specific experience was reviewed and
 
considered in the program. The staff found that the proposed program will provide
 
assurance that bus ducts are not exposed to excessive ohmic or ambient heating.
The staff confirmed that the operating experi ence program element satisfies the criteria defined in SRP-LR Section A.1.2.3.10. The staff concluded that this program attribute is
 
acceptable.
In reviewing the program elements and based on implementation of the Bus Inspection Program, the staff found that there is reasonable assurance that the aging effects of
 
non-segregated phase bus insulation and loosening of fastening hardware associated with
 
isolated and non-segregated phase bus will be adequately managed such that isolated and
 
non-segregated phase bus will continue to perform its intended functions for the period of
 
extended operation.
UFSAR Supplement. In LRA Section A.2.2, the applicant provided the UFSAR supplement for the Bus Inspection Program. The staff reviewed this section and determined that the information
 
in the UFSAR supplement provides an adequate summary description of the program. The staff
 
found this section of the UFSAR supplement met the requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review, RAI response, and audit of the applicant's program, the staff concluded that the applicant had demonstrated that the effects of aging will be adequately
 
managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplements for this AMP and found that they provide an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3.0.3.3.3  Diesel Starting Air Program
 
Summary of Technical Information in the Application. The applicant's Diesel Starting Air Program is described in LRA Section B.2.1.41, "Diesel Starting Air Program." In the LRA, the
 
applicant stated that this is an existing plant-specific program.
3-108 The Diesel Starting Air Program manages the emergency diesel generator (EDG) starting air system. This program was origi nally developed in response to plant operating experience with corrosion in the system, and will be enhanced with additional inspections for license renewal.
 
The program includes the preventive actions of replacing filters and desiccant, and inspections
 
of the system components to verify that unacceptable corrosion is not occurring. The Diesel
 
Generator Starting Air Program is credited for managing the loss of material due to general
 
corrosion of carbon, low-alloy, cast iron, and cast-iron alloy components in the diesel generator
 
starting air system (LRA Table 3.3.2.30).
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in LRA Section B.2.1.41, regarding the applicant's demonstration of the Diesel Starting
 
Air Program to ensure that the effects of aging, as discussed above, will be adequately
 
managed so that the intended functions will be maintained consistent with the CLB throughout
 
the period of extended operation.
The staff reviewed the Diesel Starting Air Program against the AMP elements found in the SRP-LR Section A.1.2.3 and SRP-LR Table A.1-1, and focused on how the program manages
 
aging effects through the effective incorporation of 10 elements (i.e., program scope, preventive actions, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and
 
operating experience).
The applicant indicated that the corrective actions, confirmation process, and administrative controls are part of the site-controlled quality assurance program. The staff's evaluation of the
 
quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements
 
are discussed below.  (1)Scope of Program - In LRA Section B.2.1.41, the applicant stated that the program scope includes the starting air systems for the EDGs. LRA Table 3.3.2.30 shows that the
 
program is used to manage general corrosion of carbon and
 
low-alloy steel, as well as cast iron and cast-iron alloy components in an air/gas internal
 
environment. The components include air-start motors, fittings, piping, strainers, tanks, tubing, and valves.
The staff confirmed that the scope of the program element satisfies the criterion defined in SRP-LR Section A.1.2.3.1. The staff concluded that this program attribute is
 
acceptable.
 
  (2)Preventive Actions - In LRA Section B.2.1.41, the applicant stated that the mitigative actions include filter replacement and desiccant replacement. These actions maintain
 
the air quality and thereby reduce corrosion. The staff found that these are appropriate
 
preventive measures for reducing the e ffects of aging of the EDG air system.
The staff confirmed that the preventive actions program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2. The staff concluded that this program attribute is
 
acceptable.    (3)Parameters Monitored or Inspected - In LRA Section B.2.1.41, the applicant stated that the program provides for periodic inspection of moisture traps, pilot valves, and lift check 3-109 valves for corrosion, erosion, pitting, and wear. These inspections are beyond the identified aging effects of the long-lived passive components covered by the scope of the
 
Rule (and included in LRA Table 3.3.2.20), but are acceptable because they will provide
 
early indication of aging that would result from a reduction of air quality, and will address
 
the plant operating experience (see below). The LRA also states that the diesel
 
generator starting air piping and receivers will be inspected for loss of material using the
 
One-Time Inspection Program. The staff considers this an acceptable inspection for
 
confirming that any aging is not significant.
The staff confirmed that the parameters monitored or inspected program element satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff concluded that this
 
program attribute is acceptable.    (4)Detection of Aging Effects - In LRA Section B.2.1.41, the applicant stated that the detection of aging effects is through the periodic visual inspection of the moisture traps, pilot valves, and lift check valves. The inspections are for corrosion, erosion, pitting, and
 
wear. In addition, the LRA states that the One-Time Inspection Program will be used to
 
inspect for loss of material in the emergency diesel starting air system piping and
 
receivers. The staff's review of the One-Time Inspection Program is in SER
 
Section 3.0.3.1.7. The staff found that these are appropriate inspections for the identified
 
aging effects.
The staff confirmed that the detection of aging effects program element satisfies the criterion defined in SRP-LR Section A.1.2.3.4. The staff concluded that this program
 
attribute is acceptable.    (5)Monitoring and Trending - In LRA Section B.2.1.41, the applicant stated that this program is implemented through the Prev entive Maintenance Program, which includes provisions for monitoring and trending. In addition, failure to meet acceptance criteria will
 
result in corrective actions. The staff found that this is reasonable and acceptable
 
monitoring and trending.
The staff confirmed that the monitoring and trending program element satisfies the criteria defined in SRP-LR Section A.1.2.3.5. The staff concluded that this program
 
attribute is acceptable.    (6)Acceptance Criteria - In LRA Section B.2.1.41, the applicant stated that the acceptance criteria are typically qualitative. An exam ple would be "absence of corrosion." If these criteria are not met, corrective actions result in an evaluation to ensure that the intended
 
functions are maintained. The staff found that performing an evaluation to ensure the
 
intended functions are maintained is an acceptable method of managing aging.
The staff confirmed that the acceptance criter ia program element satisfies the criteria defined in SRP-LR Section A.1.2.3.6. The staff concluded that this program attribute is
 
acceptable.    (10)Operating Experience - In LRA Section B.2.1.41, the applicant stated that during the 1980s, the diesel generator air-start system experienced failures of the air-start solenoid
 
valves during a start sequence. The air-start motor did not disengage due to corrosion 3-110 debris, which pitted the air solenoid valve seats, preventing the air-start solenoid valves from completely closing. In response, the applicant modified the system by installing air dryers and moisture traps, implemented periodic maintenance including the replacement
 
of filters and desiccant, and verified the effectiveness of the modifications with
 
inspections.
The staff confirmed that the operating experi ence program element satisfies the criteria defined in SRP-LR Section A.1.2.3.10. The staff concluded that this program attribute is
 
acceptable.
UFSAR Supplement. In LRA Section A.2.3, the applicant provided the UFSAR supplement for the Diesel Starting Air Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the
 
program. The staff found this section of the UFSAR supplement met the requirements of
 
10 CFR 54.21(d).
Conclusion. On the basis of its review of the applicant's program, the staff determined that the applicant had demonstrated that it will adequately manage the effects of aging so that the
 
intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement
 
for this AMP and concluded that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.3.4  Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program (B.2.1.13)
 
Summary of Technical Information in the Application. In its response to RAI 3.1.2.2-9 (see Section 3.1.2.3.17), the applicant determined that this program should be deleted, however, the
 
staff decided to keep the evaluation as follows for the limited program scope.
The Thermal Aging Embrittlement of CASS Program is discussed in LRA Section B.2.1.13. The applicant stated that the only CASS components within the scope of license renewal that were
 
determined to be susceptible to thermal aging embrittlement are the main steam line
 
flow-restricting venturis. The material of the venturis is low-molybdenum with a delta ferrite
 
content of 18.3 percent. The venturis are exposed to a reactor steam environment that is lessthan 320 °C (610 °F). The applicant stated that, based on evaluation of material and
 
environmental characteristics in accordance with the guidelines of EPRI Technical Report
 
1000976, "Evaluation of Thermal Aging Embrittlement for Cast Austenitic Stainless Steel
 
Components - January 2001," a Thermal Aging Embrittlement of CASS Program is not required.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the applicant's Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program to determine the
 
validity of the applicant's conclusion that a Thermal Aging Embrittlement of CASS Program is
 
not required, and to ensure that the intended function(s) of the components will be maintained
 
consistent with the CLB for the period of extended operation.
CASS exposed to elevated temperatures is subject to thermal aging during service. The effects of thermal aging include increases in tensile and a decrease in fracture toughness. The
 
decrease in fracture toughness is proportional to the level of ferrite in the material. Thermal
 
aging of susceptible materials will continue until a saturation or fully aged point is reached. The 3-111 staff's position regarding thermal aging of CASS components is detailed in the letter from Christopher Grimes (NRC) to Douglas Waters, (NEI), dated May 19, 2000. In order to determine
 
if the applicant evaluated the CASS components in accordance with the aforementioned letter, the staff requested additional information from the applicant. The applicant responded to the
 
staff's RAI as discussed below.
In RAI B.2.1.13-1, the staff requested that the applicant provide the material specification including material grade, chemical content, casting method, percent ferrite, and operating
 
temperature for the flow-restricting venturis. The staff also requested the applicant to confirm
 
that the flow-restricting venturis had been evaluated in accordance with the above referenced
 
staff letter dated May 19, 2000, and to state if the venturis were potentially susceptible to
 
thermal aging embrittlement when screened using the criteria outlined in the aforementioned
 
letter.
 
In its response, by letter dated December 9, 2004, the applicant stated that the main steam line
 
flow-restricting venturis are ASTM A 351 Grade CF8. The actual chemistry and casting method are not known by the applicant. The operating temperature of the main steam line is 550 °F, and
 
the applicant calculated the delta ferrite content to be 18.3 percent. Although the applicant does
 
not know the precise chemistry of the components, it used worst-case values for the chemistry
 
range of ASTM A 351 Grade CF8, as listed in the 1975 Annual Book of ASTM Standards, to
 
calculate the delta ferrite content using Hull's equivalent factors in NUREG/CR-4513, "Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems."Based on the screening criteria listed in Table 2 of the NRC letter dated May 19, 2000, neither statically or centrifugally cast components with a low molybdenum content (0.5 percent max.)
 
and a delta ferrite level less than 20 percent are susceptible to thermal aging embrittlement. The
 
applicant stated in its response to RAI B.2.1.13-1 that the CASS flow-restricting venturis have
 
been evaluated for thermal aging in accordance with the guidance detailed in the May 19, 2000, NRC letter. Based on the applicant's evaluation of the flow-restricting venturis in accordance
 
with the NRC letter, the staff found acceptable the applicant's conclusion that a CASS AMP is
 
not required.
Conclusion. The staff reviewed the information provided in LRA Section B.2.1.13 as supplemented by the applicant's response to the staff's RAI. On the basis of this review, the
 
staff concluded that the applicant had demonstrated that a thermal aging embrittlement of CASS
 
AMP is not required and hence no aging management for Thermal Aging Embrittlement of Cast
 
Austenitic Stainless Steel Program, as required by 10 CFR 54.21(a)(3), is required for the only
 
CASS components within the scope of license renewal in the LRA application.
3.0.3.3.5  Unit 1 Periodic Inspection Program (B.2.1.42)
 
Summary of Technical Information in the Application. In the LRA, the applicant did not include a description of the new, plant-specific AMP B.2.1.42, "Unit 1 Periodic Inspection Program."
 
During the course of the staff's AMR of Unit 1 systems in layup for the extended outage, it was
 
realized that neither the GALL-recommended one-time inspection nor the Unit 1 restart
 
inspection would be sufficient in itself to monitor the effects of any new degradation that will
 
manifest during the period of extended operation. This plant-specific program is designed to
 
monitor the condition of and perform periodic inspections of components that were in layup and 3-112 have been requalified without replacement. A program description and a history of the program development is described below (see Sections 3.7.1.2 and 3.7.1.3).
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in AMP B.2.1.42 regarding the applicant's demonstration of the Unit 1 Periodic
 
Inspection Program to ensure that the effects of aging will be adequately managed so that the
 
intended functions will be maintained consistent with the CLB throughout the period of extended
 
operation.
The staff reviewed the Periodic Inspection Program against the AMP elements found in the SRP-LR Section A.1.2.3 and Table A.1-1, and focused on how the program manages aging
 
effects through the effective incorporation of the 10 program elements (i.e., program scope, preventive actions, parameters monitored or ins pected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative
 
controls, and operating experience).
The applicant indicated that the corrective actions, confirmation process, and administrative controls are part of the site-controlled quality assurance program. The staff's evaluation of the
 
quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements
 
are discussed below.
The program was initially submitted for review by TVA letter dated August 4, 2005. The staff review determined that the required information submitted was not entirely complete or
 
consistent with the information identified in SRP-LR Section A.1.2.3. On September 2, 2005, in an informal communication (8 staff questions) and in a formal meeting summary dated October
 
31, 2005, the staff requested additional information to support their review. The program was
 
revised and resubmitted by TVA letter dated November 16, 2005.
In NRC Question 1, the staff requested the applicant to review the entire SRP-LR Section A.1.2.3 and to include additional applicable information. In NRC Question 2, the staff also
 
identified a general concern that, in the description of the program, the use of the term "failures"
 
is not appropriate for license renewal. In response, the applicant revised the term "failures" to
 
read, "acceptable degradation." The applicant also revised the UFSAR Section A.2.4 and the
 
description of each element to include the information identified in SRP-LR Section A.1.2.3, as
 
discussed below.  (1)Scope of Program - In AMP Section B.2.1.42, the applicant stated that the program provides periodic monitoring of the non-replaced piping/fittings that were not in service
 
supporting operation of Units 2 and 3. This piping is carbon/low-alloy or stainless steel
 
that was exposed to air, treated water, or raw water during the extended Unit 1
 
shutdown. The susceptible locations identified are those areas determined to have the
 
highest potential for service-induced wear or latent aging effects. The staff found, in
 
general, the scope of the program to be comprehensive and acceptable because it
 
includes components that were subject to lay-up at locations most susceptible to
 
degradation as a result of the extended outage.
The applicant's response to Question 3, letter dated November 16, 2005 revision, did not include a detailed AMR table (Table 3) in a standard format. The format should include listing of system and components, and specify reference to the new Inspection program, "B.2.1.42 Unit 1 Periodic Inspection Program." as the AMP. This did not allow a staff review of specific combinations of 3-113 components, materials, environments and agi ng effects to be managed by the new Unit 1 Periodic Inspection Program. In addition, the applicant did not respond to NRC
 
Question 3(b) concerning the number of sample locations. Instead, the applicant stated
 
that its earlier response, dated May 18, 2005, in a table titled,"NDE Examinations
 
Performed for Original Non-replaced Piping, (3 sheets)," had identified specific
 
components, piping, and welds that will be included in the scope of this new program.
 
The applicant stated that the table included piping and welds in the RHRSW, Fire
 
protection, EECW, RCW, CRD, CS, FW, HPCI, MS, RCIC, RHR, and RBCW systems.
 
The staff accepts this list to satisfy the requirement of the program element "scope" in
 
lieu of the detailed AMR table for purpose of this evaluation. However, in a
 
teleconference with the applicant on December 7, 2005, the applicant agreed (letter
 
dated December 20, 2005) to perform a revision of the LRA AMR Tables (Table 3) to
 
add the newly identified piping and components that will be included in the scope of the
 
program and identify these in appropriate systems tables in a future revision.
Also, the applicant agreed to review the adequacy of the number of sample locations on the basis of a 95/95 confidence level.
The staff confirmed that the scope of the program element satisfies the criterion defined in SRP-LR Section A.1.2.3.1. The staff concluded that the program attribute is
 
acceptable.    (2)Preventive Actions - In the initial program Element 2, the applicant identified the Unit 1 Periodic Inspection Program as a detection program. Programs are normally identified
 
as condition monitoring, performance monito ring, or prevention and mitigation programs.
In NRC Question 5, the staff requested the applicant to clarify that the program is a
 
condition monitoring program. In the revised AMP Section B.2.1.42, the applicant stated
 
that the program is a condition monitoring program and, thus, there are no preventive actions. The staff concurred with this assessment and does not identify the need for any
 
preventive actions associated with this program.
The staff confirmed that the preventive actions program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2. The staff concluded that the program attribute is
 
acceptable.    (3)Parameters Monitored or Inspected - In AMP Section B.2.1.42, the applicant clarified that the Unit 1 Periodic Inspection Program is a condition monitoring program and only
 
the first two items of the SRP-LR are applicable. The applicant identified that the
 
selected sample will be examined by the same or equivalent, methodology (UT
 
thickness for piping and UT shear wave and surface exam for weld), as performed to
 
determine acceptability of not replacing piping sections prior to restart. The applicant
 
stated that the susceptible locations were those areas determined to have the highest
 
potential for service-induced wear or latent aging effects, which includes all types of
 
corrosion. The applicant also identified that the inspection techniques utilized evaluate
 
internal conditions and are sensitive to the presence of unacceptable conditions, including wear, erosion, corrosion (including crevice corrosion) if present. In addition, the
 
applicant initially identified that the sample selected for periodic inspection will be based
 
on a 90/90 confidence level consistent with the methodology identified in EPRI 107514.
 
The staff was concerned that a 90/90 confidence level may not be appropriate and that
 
EPRI 107514 had not been reviewed by the staff. In NRC Question 4, the staff 3-114 requested the applicant to clarify whether application of EPRI 107514 represented an industry consensus for selecting a sample on the basis of 90/90 criteria. The applicant
 
was also requested to identify the sample size on the basis of 90/90 criteria versus
 
95/95 and to justify selecting a sample size on the basis of the 90/90 criteria versus the
 
more restrictive 95/95 criteria. In its response, dated November 16, 2005, the applicant
 
revised the sample size basis to reflect a confidence level of 95/95 and replaced the
 
EPRI reference with "Elementary Statistical Analysis." The staff's review of the
 
acceptability of the revised basis for the sample size is further discussed under
 
Element 4. The staff found that the paramet ers monitored or inspected will provide symptomatic evidence of potential degradation and, therefore, are acceptable.
The staff confirmed that the parameters monitored or inspected program element satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff concluded that this
 
program attribute is acceptable.  (4)Detection of Aging Effects - SRP Section A.1.2.3.4 states that the applicant is to provide justification, including codes and standards referenced, that the inspection technique
 
and frequency are adequate to detect the aging effects before a loss of SC intended function. In the initial submittal of AMP B.2.1.42, the applicant did not identify any codes and standards. In NRC Question 6, the staff requested the applicant to include additional
 
information to demonstrate that the technique and frequency of future inspections is
 
justified. In revised AMP Section B.2.1.42, in its submittal dated November 16, 2005, the
 
applicant stated that the program is not covered by industry codes or standards and the
 
selected inspection methodologies are based on the inspections performed to determine
 
whether components require replacement prior to restart. The applicant also stated that
 
the examination techniques utilized for the baseline inspection were ultrasonic thickness
 
measurements for the piping and ultrasonic shear wave for welds. The applicant
 
identified that the restart inspections can be used as a baseline and additional periodic
 
inspections of sample locations will be performed after Unit 1 is returned to service and
 
again within the first ten years of the period of extended operation. The use of ultrasonic
 
thickness measurements and ultrasonic shear wave techniques should be capable of
 
detecting most forms of internal degradation of the piping and welds caused by the
 
extended outage. The staff was concerned that inspections may not be performed to
 
recognized codes and standards and UT inspection may not be the best technique to
 
detect certain types of corrosion. The staff believes that codes and standards such as
 
ASME Section V and ASTM, are appropriate references. Based on industry standards
 
such as ASTM G46-94 and standard practices identified in EPRI documents and the
 
GALL Report, visual inspections may be a more appropriate technique to identify certain
 
types of internal degradation, such as pitting and MIC. Therefore, the applicant was
 
requested to identify specific codes and standards used for periodic inspections and
 
evaluate the acceptability of UT alone to detect all forms of corrosion. In a
 
teleconference with the applicant on December 7, 2005 (applicant submittal dated
 
December 20, 2005) the applicant indicated that internal visual inspections are
 
performed as part of other aging management programs when the system is open, but UT is preferred for periodic inspection trending purposes, since opportunistic internal
 
inspections are limited by accessibility.
The applicant stated that it will also perform suitable trending for degradations that could appear during the extended operation, and will apply BFN's Corrective Action Program including appropriate mitigative action if any degradation could lead to loss of intended function. The staff found that a combination of 3-115 opportunistic internal visual inspections combined with periodic UT inspections to be acceptable techniques to detect latent aging effects.
In regard to the basis for the sample size addressed in the SRP-LR "Detection of Aging Effects" element, the applicant described the sample size basis under Element 3, "Parameters Monitored or Inspected.
" The applicant applied a statistical analysis to establish a confidence level of 95/95 for selecting a sample size within a common
 
material and environment. In SER Section A.2.4, submitted by letter dated October 19, 2005, the applicant stated that if unacceptable degradation is identified, the sample size
 
will be appropriately expanded. Although the applicant did not respond to staff's request
 
in NRC Question 3(b) concerning the number of sample locations (scope) to be
 
inspected, the applicant did adequately identify the basis for the sample size.
The staff concurred that application of periodic internal visual and ultrasonic inspections are acceptable to detect that aging effects may be occurred during the extended outage.
The staff found that the 95/95 confidence level is an acceptable basis for determining an adequate sample size and that a provision to expand the sample size is consistent with
 
industry practice and SRP-LR Section A.1.2.3.4. The staff concluded that this program
 
attribute is acceptable.  (5)Monitoring and Trending - In the initial submittal of AMP B.2.1.42, the applicant did not identify if results will be monitored and trended. In NRC question 7, the staff requested
 
the applicant to clarify that results will be monitored and trended. In its response, the
 
applicant confirmed that the program has been revised to clarify the requirement to
 
monitor and trend the results of periodic inspections. In revised AMP Section B.2.1.42, the applicant stated that the inspection frequency is re-evaluated each time the
 
inspection is performed and can be changed based on the trend of the results. SRP-LR
 
Section A.1.2.3.5 states that plant-specific and/or industry-wide operating experience
 
may be considered in evaluating the appropriateness of the technique and frequency.
 
The staff found that the overall monitoring and trending proposed by the applicant are
 
acceptable because there is reasonable assurance that effective periodic inspections
 
combined with the Corrective Action Program will effectively manage the applicable
 
aging effects.
The staff confirmed that the monitoring and trending program element satisfies the criterion defined in SRP-LR Section A.1.2.3.5. The staff concluded that this program
 
attribute is acceptable.  (6)Acceptance Criteria - In AMP Section B.2.1.42, the applicant stated that the acceptance criteria is that the pipe wall will remain above minimum acceptable wall thickness until
 
the next periodic inspection, and that no unacceptable weld cracks exist. The staff found
 
that the application of minimum wall thickness and no unacceptable weld cracks based
 
on the Code of record to be reasonable and appropriate acceptance criteria to maintain
 
the intended functions of the components inspected.
The staff confirmed that the acceptance criter ia program element satisfies the criterion defined in SRP-LR Section A.1.2.3.6. The staff concluded that this program attribute is
 
acceptable.
3-116  (10)Operating Experience - In NRC Question 8 of the informal staff request of September 2, 2005, the staff requested the applicant to identify a commitment to provide (or have
 
available for review) operating experience for this new program in the future to confirm
 
its effectiveness. The applicant's response confirmed that the program has been revised
 
to clarify the requirement to evaluate the results of the periodic inspections to verify
 
program effectiveness. In the revised version of AMP Section B.2.1.42, the applicant
 
stated that the Unit 1 Periodic Inspection Program is a new program that will monitor the
 
operating conditions of Unit 1 components that were not replaced during the Unit 1
 
restart. The applicant credits the trending data developed in Element 5 to demonstrate
 
the effectiveness of the Unit 1 Periodic Inspection Program. The staff found that there is
 
reasonable assurance that the use of trending data will provide objective evidence to
 
determine the effectiveness of the periodic inspection program.
The staff confirmed that the operating experienc e program element satisfies the criterion defined in SRP-LR Section A.1.2.3.10. The staff concluded that this program attribute is
 
acceptable.
UFSAR Supplement. By letter dated November 16, 2005, the applicant provided the following UFSAR supplement for the Unit 1 Periodic Inspection Program:
The Unit 1 Periodic Inspection Program is a new program that performs periodic inspections of the non-replaced piping/fittings that were not in service supporting
 
operation of Units 2 and 3 following the extended Unit 1 outage to verify that no latent
 
aging effects are occurring, and to correct degraded conditions prior to loss of function.
During the Unit 1 restart project, examinations were performed to verify acceptability of the existing piping that was not replaced. The specific examinations are discussed in the
 
TVA Letter to the U.S. Nuclear Regulatory Commission, Document Control Desk, "Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 - License Renewal Application (LRA) - Response to NRC Request for Additional Information Concerning the Unit 1
 
Lay-up Program (TAC Nos. MC1704, MC1705, and MC1706)" dated May 18, 2005. This
 
piping is carbon/low-alloy or stainless steel that was exposed to air, treated water, or raw
 
water during the extended Unit 1 shutdown. The Unit 1 Periodic Inspection Program will
 
examine a sample of those locations examined for plant restart as discussed in the
 
referenced letter to verify that no latent aging effects are occurring. The sample size will
 
be determined in accordance with the sampling methodology described in S. S. Wilks, "Elementary Statistical Analysis," Princeton University Press, 1948. If unacceptable
 
degradation is identified, the sample size will be appropriately expanded. The initial
 
sample, once selected, will be utilized in subsequent inspections, if practical.
These periodic inspections are in addition to the restart inspections performed prior to Unit 1 restart. The Unit 1 periodic inspections will be performed after Unit 1 is returned to
 
operation. The susceptible locations identified are those areas determined to have the
 
highest potential for service-induced wear or latent aging effects. The inspection
 
techniques utilized evaluate internal conditions that are sensitive to the presence of
 
unacceptable conditions including wear, erosion, and corrosion (including crevice
 
corrosion) if present. For these locations, the restart inspections can be utilized as a
 
baseline for comparison.
3-117 The Unit 1 periodic inspections will be performed after Unit 1 is returned to operation and prior to the end of the current operating period. The second periodic inspection of all
 
sample locations will be completed within the first ten E2-9 years of the period of
 
extended operation. The inspection frequency is re-evaluated each time the inspection is
 
performed and can be changed based on the trend of the results. The inspections will
 
continue until the trend of the results provides a basis to discontinue the inspections.
The staff reviewed the above UFSAR supplement and determined that it provides an adequate summary description of the program. The staff found that this section of the UFSAR supplement
 
met the requirements of 10 CFR 54.21(d).
Conclusion. On the basis of its review of the applicant's program, the staff found that the Unit 1 Periodic Inspection Program adequately addresses the 10 program elements identified in
 
Appendix A of the SRP-LR, and that the program will adequately manage the aging effects for
 
which it is credited. The staff also reviewed the UFSAR supplement for this aging management program and found that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d). 3.0.4  Quality Assurance Program Attribut es Integral to Aging Management Programs Pursuant to 10 CFR 54.21(a)(3), a license renewal applicant is required to demonstrate that the effects of aging on SCs subject to an AMR will be adequately managed so that their intended
 
functions will be maintained consistent with the CLB for the period of extended operation.
 
SRP-LR, Branch Technical Position RLSB-1, "Aging Management Review - Generic," describes
 
ten attributes of an acceptable AMP. Three of these ten attributes are associated with the
 
quality assurance activities of corrective action, confirmation processes, and administrative
 
controls. Table A.1-1, "Elements of an Agi ng Management Program for License Renewal," of Branch Technical Position RLSB-1 provides the following description of these quality attributes:
* Corrective actions, including root cause determination and prevention of recurrence, should be timely.
* The confirmation process should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective.
* Administrative controls should provide a formal review and approval process.
SRP-LR, Branch Technical Position IQMB-1, "Quality Assurance For Aging Management Programs," noted that those aspects of the AMP that affect quality of SR SSCs are subject to
 
the quality assurance (QA) requirements of 10 CFR Part 50, Appendix B. Additionally, for NSR
 
SCs subject to an AMR, the existing 10 CFR Part 50, Appendix B, QA program may be used by
 
the applicant to address the elements of corrective action, the confirmation process, and
 
administrative controls. Branch Technical Position IQMB-1 provides the following guidance with
 
regard to the QA attributes of AMPs:
* SR structures and components are subject to 10 CFR Part 50, Appendix B, requirements, which are adequate to address all quality-related aspects of an AMP
 
consistent with the CLB of the facility for the period of extended operation.
3-118
* For NSR SCs that are subject to an AMR for license renewal, an applicant has an option to expand the scope of its 10 CFR Part 50 Appendix B program to include these
 
structures and components to address corrective actions, the confirmation process, and
 
administrative controls for aging management during the period of extended operation.
In this case, the applicant should document such a commitment in the FSAR supplement
 
in accordance with 10 CFR 54.21(d).
3.0.4.1  Summary of Technical Information in the Application LRA Section 3.0, "Aging Management Review Results," provides an AMR summary for each unique structure, component, or commodity group at Units 2 and 3, (Unit 1 is in an extended
 
outage) determined to require aging management during the period of extended operation. This
 
summary includes identification of aging effects requiring management and AMPs utilized to
 
manage these aging effects. LRA Appendix A, "UFSAR Supplement," and Appendix B, "Aging
 
Management Program Descriptions," demonstrat e how the identified programs manage aging effects using attributes consistent with the industry and staff guidance. In LRA Appendix A, the
 
applicant does not commit that the QA Program includes the elements of corrective action, confirmation process, and administrative controls or that it is applicable to both SR and NSR
 
SSCs that are within the scope of license renewal. However, in LRA Section B.1.3, "Quality
 
Assurance and Administrative Controls," in "Aging Management Program Descriptions," the
 
applicant stated that the QA Program implements the requirements of 10 CFR  Part 50, Appendix B, and is consistent with the summary in SRP-LR Appendix A.2 (Reference B-1). The
 
QA Program includes the elements of corrective action, confirmation process, and
 
administrative control, and it is applicable to the SR and NSR SSCs that are subject to an AMR.
 
In many cases, existing programs were f ound to be adequate for managing aging effects during the period of extended operation. Generically, the three elements are applicable as follows:
Corrective Action. A single corrective action process is applied regardless of the safety classification of the structure or component. Corrective actions are implemented through the
 
initiation of a Problem Evaluation Report (PER) in accordance with the applicant's nuclear
 
procedure established to implement the provisions of 10 CFR Part 50 Appendix B. Plant
 
procedures require the initiation of a PER to document actual or potential problems, including
 
unexpected plant equipment degradation, damage, failure, malfunction, or loss. Site procedures
 
that implement aging management activities for license renewal require that a PER be prepared
 
whenever non-conforming conditions are found (i.e., the acceptance criteria are not met).
 
Equipment deficiencies are corrected through the initiation of a work order in accordance with
 
plant procedures. Although equipment deficiencies may initially be documented by a work order, the corrective action process specifies that a PER also be initiated if required.
Confirmation Process. The confirmation process ensures that follow-up actions are taken to verify effective implementation of corrective ac tions. The measure of effectiveness is in terms of correcting the adverse conditions and precluding their recurrence. Relevant applicant
 
procedures include provisions for timely evaluat ion of adverse conditions and implementation of any corrective actions required, including root cause determinations and prevention of
 
recurrence where appropriate. The procedure requires determinations. The corrective action
 
process also requires monitoring for potentially adverse trends. A PER is required if adverse trends persist. Since the same 10 CFR 50, Appendix B, corrective action and confirmation
 
process is applied for nonconforming SR and NSR SCs subject to AMR for license renewal, the
 
Corrective Action Program is consistent with the GALL Report.
3-119 Administrative Controls. AMPs are administered through various plant implementation documents, which are subject to administrative controls, including a formal review and approval process in accordance with the requirements of 10 CFR  Part 50, Appendix B, and, therefore
 
are consistent with SRP-LR.
3.0.4.2  Staff Evaluation The staff reviewed the applicant's QA controls for AMPs as described in the LRA. The purpose of this review was to assure that the aging management activities were consistent with the
 
staff's guidance described in SRP-LR, Section A.2, "Quality Assurance for AMPs (Branch
 
Technical Position IQMB-1)," regarding QA attributes of AMPs. Based on the staff's evaluation, the descriptions and applicability of the plant-specific AMPs and their quality attributes provided
 
in LRA Appendix B.1.3 are consistent with the staff's position regarding QA for aging
 
management. In particular, the applicant noted t hat its QA Program provides elements of corrective action, confirmation processes, and administrative controls for both SR and NSR
 
SSCs. However, the applicant did not describe the use of the QA Program and its associated
 
attributes in LRA Appendix A, "UFSAR" Appendix A. Specifically, consistent with Branch Technical Position IQMB-1, the applicant should either document a commitment to expand the
 
scope of its 10 CFR Part 50 Appendix B program to include NSR SCs subject to an AMP to
 
address the AMP quality attributes during the period of extended operation, or propose an
 
alternate means to address this issue. In RAI 2.1-3. dated July 30, 2004, the staff requested the
 
applicant to clarify its position with regard to the quality attributes of AMPs in LRA Appendix A.
 
By letter dated September 3, 2004, the applicant responded as follows:
The following statement supplements LRA A ppendix A.1, "Aging Management Programs:" The integrated plant assessment for license renewal identified new programs, enhancements to existing programs, and exis ting programs necessary to continue operation of BFN Units 1, 2, and 3 during the additional twenty years beyond the initial
 
license term. This chapter describes those programs. The TVA Nuclear Quality
 
Assurance Program implements the requirements of 10 CFR 50, Appendix B. The TVA
 
Nuclear Quality Assurance Program includes elements of corrective action, confirmation
 
process, and administrative controls. These elements are applicable to all aging
 
management programs credited for license renewal. The Corrective Action Program ensures corrective actions, including root cause determinations and prevention of
 
recurrence are timely. The Corrective Action Program also includes the confirmation
 
process that ensures preventive actions are adequate and that appropriate corrective
 
actions have been complete and are effective. Administrative controls provide for a
 
formal review and approval process of program implementing documents.
The staff reviewed the statement and requested that the applicant revise the statement made in its September 24, 2004, response to explicitly state that the applicant's 10 CFR  Part 50, Appendix B, Quality Assurance Program will apply to both SR and NSR SSCs within the scope
 
of license renewal and subject to one or more of the AMPs.
By letter dated October 18, 2004, the applicant provided a supplemental response, which stated, in part, that the elements (corrective action, confirmation process, and administrative controls) are applicable to all AMPs, SSCs, systems, and components. The staff reviewed the
 
revised response and finds that it adequately addresses the staff's concerns regarding 3-120 application of the AMPs to both SR and NSR SSCs within the scope of license renewal and subject to one or more of the AMPs, and is, therefore, acceptable. The staff considered the
 
information provided by the applicant acceptable and the staff's concern described in RAI 2.1-3
 
is resolved.
3.0.4.3  Conclusion The staff found that the QA attributes of the applicant's AMPs are consistent with 10 CFR 54.21(a)(3). Specifically, the applicant described the quality attributes of the programs
 
and activities for managing the effects of aging for both SR and NSR SSCs within the scope of
 
license renewal and stated that 10 CFR Part 50 Appendix B provides corrective actions, confirmation processes, and administrative controls. Therefore, the applicant's QA description
 
for its AMPs is acceptable.
3-1213.1  Aging Management Review of Reactor Vessel, Internals, and Reactor Coolant System This section of the SER documents the staff's review of the applicant's AMR results for the reactor vessel, internals, and reactor coolant system components and component groups
 
associated with the following systems:
* reactor vessel
* reactor vessel internals
* reactor vessel vents and drains
* reactor recirculation3.1.1  Summary of Technical Information in the Application In LRA Section 3.1, the applicant provided AMR results for components. In LRA Table 3.1.1,"Summary of Aging Management Review Evaluati ons for Reactor Coolant System Evaluated in Chapter IV of NUREG-1801," the applicant provided a summary comparison of its AMRs with
 
the AMRs evaluated in the GALL Report for the reactor vessel, internals, and reactor coolant
 
system components and component groups.
The applicant's AMRs incorporated applicable operating experience in the determination of AERMs. These reviews included evaluation of plant-specific and industry operating experience.
 
The plant-specific evaluation included reviews of condition reports and discussions with
 
appropriate site personnel to identify AERMs. The applicant's review of industry operating
 
experience included a review of the GALL Report and operating experience issues identified
 
since the issuance of the GALL Report.
 
====3.1.2 Staff====
Evaluation The staff reviewed LRA Section 3.1 to determine if the applicant had provided sufficient information to demonstrate that the effects of aging for the reactor vessel, internals, and reactor
 
coolant system components that are within the scope of license renewal and subject to an AMR
 
will be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff performed an onsite audit of AMRs during the weeks of June 21 and July 26, 2004, to confirm the applicant's claim that certain identified AMRs were consistent with the GALL Report.
 
The staff did not repeat its review of the matters described in the GALL Report; however, the
 
staff did verify that the material presented in the LRA was applicable and that the applicant had
 
identified the appropriate GALL AMRs. The staff's evaluations of the AMPs are documented in
 
SER Section 3.0.3. Detail of the staff's audit evaluation are documented in the BFN audit and
 
review report and are summarized in SER Section 3.1.2.1.
In the onsite audit, the staff also selected AMRs that were consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further
 
evaluations were consistent with the acceptance criteria in SRP-LR Section 3.1.2.2. The staff's
 
audit evaluations are documented in the BFN audit and review report and are summarized in
 
SER Section 3.1.2.2.
3-122 In the onsite audit, the staff also conducted a technical review of the remaining AMRs that were not consistent with, or not addressed in, the GALL Report. The audit and technical review
 
included evaluating whether all plausible aging effects were identified and evaluating whether
 
the aging effects listed were appropriate for the combination of materials and environments
 
specified. The staff's audit evaluations are documented in the BFN audit and review report and
 
are summarized in SER Section 3.1.2.3. The staff's evaluation of its technical review is also
 
documented in SER Section 3.1.2.3.
Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or
 
monitoring aging for the reactor vessel, internals, and reactor coolant system components.
Table 3.1-1 below provides a summary of the staff's evaluation of components, aging effects/mechanisms, and AMPs listed in LRA Section 3.1, that are addressed in the GALL
 
Report.Table 3.1-1  Staff Evaluation for Reactor Vessel, Internals, and Reactor Coolant System Components in the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation Reactor coolant pressure boundary
 
components (Item Number
 
3.1.1.1)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAAThis TLAA is evaluated in
 
Section 4.3, Metal Fatigue Isolation condenser (Item Number
 
3.1.1.3)Loss of material due to general, pitting, and crevice
 
corrosion Inservice InspectionProgram; Water Chemistry ProgramN/ANot applicableBFN does not have
 
isolation condenser The isolation
 
condenser function is performed by the RCIC system Pressure vessel ferritic materials that
 
have a neutron
 
fluence greater than
 
10 17 n/cm 2 (E > 1 MeV)
(Item Number
 
3.1.1.4)Loss of fracture toughness due to
 
neutron irradiation
 
embrittlementTLAA, evaluated inaccordance with
 
Appendix G of 10 CFR 50 and
 
RG 1.99 Reactor Vessel Surveillance
 
ProgramTLAAConsistent withGALL which
 
recommends further
 
evaluation (See Section
 
3.1.2.2.3)This TLAA is evaluated in
 
Section 4.2, Neutron Embrittlement of
 
Reactor Vessel and
 
Internals Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-123 Reactor vessel beltline shell and welds (Item Number
 
3.1.1.5)Loss of fracture toughness due to
 
neutron irradiation
 
embrittlement Reactor Vessel Surveillance
 
Program Reactor Vessel Surveillance
 
ProgramConsistent withGALL which
 
recommends further
 
evaluation (See Section 3.1.2.2.3)
Small-bore reactorcoolant system and connected systems
 
piping (Item Number
 
3.1.1.7)Crack initiation andgrowth due to stress
 
corrosion cracking (SCC), intergranular
 
stress corrosion
 
cracking (IGSCC),
and thermal and
 
mechanical loading Inservice InspectionProgram; Water Chemistry Program; One-Time inspection Program Inservice Inspection Program; Chemistry
 
Control Program; One-Time inspection ProgramConsistent withGALL which
 
recommends further
 
evaluation (See Section 3.1.2.2.4)
Jet pump sensing line and reactor
 
vessel flange leak
 
detection line (Item Number
 
3.1.1.8)Crack initiation andgrowth due to SCC, IGSCC, or cyclic
 
loadingPlant-specificStress Corrosion Cracking Program;
 
Inservice Inspection
 
Program; Chemistry
 
Control Program; One-Time Inspection Program See Section 3.1.2.3.6 Isolation condenser (Item Number
 
3.1.1.9)Crack initiation andgrowth due to SCC or cyclic loading Inservice InspectionProgram; Water Chemistry ProgramN/ANot applicableBFN does not have
 
isolation condenser The isolation
 
condenser function is performed by the RCIC system (See
 
Section 3.1.2.2.4)
Reactor vessel closure studs and
 
stud assembly (Item Number
 
3.1.1.22)Crack initiation andgrowth due to SCC
 
an/or IGSCC Reactor Head Closure Studs
 
Program Reactor Head Closure Studs
 
ProgramConsistent withGALL which
 
recommends no
 
further evaluation (See Section 3.1.2.1.12)
CASS pump casing and valve body (Item Number
 
3.1.1.23)Loss of fracture toughness due to
 
thermal aging
 
embrittlement Inservice Inspection Program Inservice Inspection ProgramConsistent withGALL which
 
recommends no
 
further evaluation (See Section 3.1.2.3.17)
CASS piping (Item Number
 
3.1.1.24)Loss of fracture toughness due to
 
thermal aging
 
embrittlementThermal Aging Embrittlement of
 
CASS ProgramN/ANot applicable No RCPB CASS
 
piping and fittings are used in BFN (See Section 3.1.2.3.17)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-124BWR piping and fittings; steam
 
generator components (Item Number
 
3.1.1.25)Wall thinning due toflow accelerated
 
corrosionFlow Accelerated Corrosion ProgramFlow Accelerated Corrosion ProgramConsistent withGALL which
 
recommends no
 
further evaluation (See Section 3.1.2.2.12)
Reactor coolant pressure boundary (RCPB) valve
 
closure bolting, manway and
 
holding bolting, closure bolting in
 
high-pressure and
 
high-temperature systems (Item Number
 
3.1.1.26)Loss of material dueto wear; loss of
 
preload due to stress relaxation;
 
and crack initiation and growth due to cyclic loading and/or
 
SCC Bolting Integrity Program Bolting Integrity ProgramConsistent withGALL which
 
recommends further
 
evaluation (See Section 3.1.2.3.4)Feedwater and control rod drive (CRD) return line
 
nozzles (Item Number
 
3.1.1.27)Crack initiation andgrowth due to cyclic
 
loadingFeedwater Nozzle Program; CRD
 
Return Line Nozzle
 
ProgramFeedwater Nozzle Program; CRD
 
Return Line Nozzle
 
ProgramConsistent withGALL which
 
recommends no
 
further evaluation (See Sections 3.1.2.2.4, 3.1.2.3.9)
Vessel shellattachment welds (Item Number
 
3.1.1.28)Crack initiation andgrowth due to SCC
 
and/or IGSCC BWR Vessel ID Attachment Welds Program; Water Chemistry Program BWR Vessel ID Attachment Welds
 
Program; Chemistry
 
Control ProgramConsistent withGALL with exceptions (See Section 3.1.2.3.7)
Nozzle safe ends, recirculation pump
 
casing, connected systems piping and fittings, body and
 
bonnet of valves (Item Number
 
3.1.1.29)Crack initiation andgrowth due to SCC
 
and/or IGSCC BWR Stress Corrosion Cracking Program; Water Chemistry Program BWR Stress Corrosion Cracking
 
Program; Chemistry
 
Control ProgramConsistent withGALL which
 
recommends further
 
evaluation (See Section 3.1.2.3.8)
Penetrations (Item Number
 
3.1.1.30)Crack initiation andgrowth due to SCC, IGSCC, and/or cyclic loading BWR Bottom Head Penetrations Program; Water Chemistry Program BWR Bottom Head Penetrations
 
Program; Chemistry
 
Control ProgramConsistent withGALL which
 
recommends further
 
evaluation (See Section 3.1.2.3.11)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-125 Core shroud and core plate, support
 
structure, top guide, core spray lines and
 
spargers, jet pump
 
assemblies, control
 
rod drive housing, nuclear instrument
 
guide tubes (Item Number
 
3.1.1.31)Crack initiation andgrowth due to SCC, IGSCC, and/or
 
irradiation assisted
 
stress corrosion
 
cracking ( IASCC)
BWR Vessel Internals Program;
 
Water Chemistry
 
Program BWR Vessel Internals Program; Chemistry Control
 
ProgramConsistent withGALL which
 
recommends further
 
evaluation (See Section 3.1.2.3.16)
Core shroud and core plate access hole cover (welded
 
and mechanical
 
covres)
(Item Number
 
3.1.1.32)Crack initiation andgrowth due to SCC, IGSCC, and/or
 
IASCCASME Section XI Inservice Inspection Program; Water Chemistry ProgramASME Section XI Inservice Inspection
 
Program; Chemistry
 
Control ProgramConsistent withGALL which
 
recommends further
 
evaluation (See Section 3.1.2.3.2)
Jet pump assembly castings and
 
orificed fuel support (Item Number
 
3.1.1.33)Loss of fracture toughness due to
 
thermal aging and
 
neutron irradiation
 
embrittlementThermal Aging and Neutron Irradiation
 
EmbrittlementN/ANot required for BFN (See Section
 
3.1.2.3.17)
Unclad top head and nozzles (Item Number
 
3.1.1.34)Loss of material due to general, pitting, and crevice
 
corrosion Inservice InspectionProgram; Water Chemistry Program Inservice Inspection Program; Chemistry
 
Control ProgramConsistent withGALL which
 
recommends further
 
evaluation (See Section 3.1.2.3.18)
The staff's review of the BFN component groups followed one of several approaches. One approach, documented in SER Section 3.1.2.1, involves the staff's review of the AMR results for
 
components in the reactor vessel, internals, and reactor coolant system that the applicant
 
indicated are consistent with the GALL Report and do not require further evaluation. Another
 
approach, documented in SER Section 3.1.2.2, involves the staff's review of the AMR results for
 
components in the reactor vessel, internals, and reactor coolant system that the applicant
 
indicated are consistent with the GALL Report and for which further evaluation is recommended.
 
A third approach, documented in SER Section 3.1.2.3, involves the staff's review of the AMR
 
results for components in the reactor vessel, internals, and reactor coolant system that the
 
applicant indicated are not consistent with, or not addressed in, the GALL Report. The staff's
 
review of AMPs that are credited to manage or monitor aging effects of the reactor vessel, internals, and reactor coolant system components is documented in SER Section 3.0.3.3.1.2.1  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Not Recommended Summary of Technical Information in the Application. In LRA Section 3.1.2.1, the applicant identified the materials, environments, and AERMs. The applicant identified the following 3-126 programs that manage the aging effects related to the reactor vessel, internals, and reactor coolant system components:
* ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program
* BWR Control Rod Drive Return Line Nozzle Program
* BWR Feedwater Nozzle Program
* BWR Penetrations Program
* BWR Vessel ID Attachment Welds Program
* BWR Stress Corrosion Cracking Program
* Chemistry Control Program
* One-time Inspection Program
* Reactor Head Closure Studs Program
* Reactor Vessel Surveillance Program
* BWR Vessel Internals Program
* Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) Program
* Bolting Integrity Program
* Flow-Accelerated Corrosion Program
* Systems Monitoring Program
* Open-Cycle Cooling Water System Program
* Selective Leaching of Materials Program Staff Evaluation. In LRA Tables 3.1.2-1 through 3.1.2-4, the applicant provided a summary of AMRs for the reactor vessel, internals, and reactor coolant system components, and identified
 
which AMRs it considered to be consistent with the GALL Report.
For component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report does not recommend further
 
evaluation, the staff performed an audit and review to determine whether the plant-specific
 
components contained in these GALL Report component groups were bounded by the GALL
 
Report evaluation.
The applicant provided a note for each AMR line item. The notes described how the information in the tables aligns with the information in the GALL Report. The staff audited those AMRs with
 
Notes A through E, which indicated the AMR was consistent with the GALL Report.
Note A indicated that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the AMP
 
identified in the GALL Report. The staff audited these line items to verify consistency with the
 
GALL Report and the validity of the AMR for the site-specific conditions.
3-127 Note B indicated that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP
 
identified in the GALL Report. The staff audited these line items to verify consistency with the
 
GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been
 
reviewed and accepted by the staff. The staff also determined whether the AMP identified by the
 
applicant was consistent with the AMP identified in the GALL Report and whether the AMR was
 
valid for the site-specific conditions.
Note C indicated that the component for the AMR line item is different from, but consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent
 
with the AMP identified by the GALL Report. This note indicates that the applicant was unable to
 
find a listing of some system components in the GALL Report. However, the applicant identified
 
a different component in the GALL Report that had the same material, environment, aging
 
effect, and AMP as the component that was under review. The staff audited these line items to
 
verify consistency with the GALL Report. The staff also determined whether the AMR line item
 
of the different component was applicable to the component under review and whether the AMR
 
was valid for the site-specific conditions.
Note D indicated that the component for the AMR line item is different from, but consistent with, the GALL Report for material, environment, and aging effect. In addition, the AMP takes some
 
exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify
 
consistency with the GALL Report. The staff verified whether the AMR line item of the different
 
component was applicable to the component under review. The staff verified whether the
 
identified exceptions to the GALL AMPs had been reviewed and accepted by the staff. The staff
 
also determined whether the AMP identified by the applicant was consistent with the AMP
 
identified in the GALL Report and whether the AMR was valid for the site-specific conditions.
Note E indicated that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited. The staff audited these line items
 
to verify consistency with the GALL Report. The staff also determined whether the identified
 
AMP would manage the aging effect consistent with the AMP identified by the GALL Report and
 
whether the AMR was valid for the site-specific conditions.
The staff conducted an audit and review of the information provided in the LRA, as documented in its BFN audit and review report. The staff did not repeat its review of the matters described in
 
the GALL Report. However, the staff did verify that the material presented in the LRA was
 
applicable and that the applicant had identified the appropriate GALL Report AMRs. The staff's
 
evaluation is discussed below.
For aging management evaluations that the applicant stated are consistent with the GALL Report and for which further evaluation is not recommended, the staff conducted its audit of the
 
LRA to determine if the applicant's reference to the GALL Report is acceptable.
The staff reviewed the LRA to confirm that the applicant: (1) provided a brief description of the system, components, materials, and environment, (2) stated that the applicable aging effects
 
had been reviewed and are evaluated in the GALL Report, and (3) identified those aging effects
 
for the reactor vessel, internals, and RCS system components that are subject to an AMR.
3-128 A review of the Table 2s identified the following issues:
The staff identified that LRA Table 3.1.2.2 presents the AMR for the reactor vessel internals core shroud and core plate (row 1). The corresponding GALL Report Item IV.B1.1-d indicates
 
that the access hole cover (AHC) welds would require an augmented inspection (UT or other
 
demonstrated acceptable inspection) to manage crack initiation due to SCC in the crevice
 
regions of the access hole covers which are not amenable to visual inspections. This issue has
 
been addressed in GE Service Information Letter (SIL) 462 (1988) after circumferential SCC
 
was found in a creviced AHC fabricated from nickel alloy 600. BFN Technical Justification
 
Number TJ-2004-02, dated 3-02-2004, provides justification for variance from GE SIL 462, revision 1, that provides guidance on inspection of core shroud AHCs. BFN has implemented
 
the GE SIL requirements for Units 2 and 3, and they will be applicable to all three units upon
 
re-start of Unit 1. Details of AHC replacements are provided in RAI 3.1.2-6(A) response, by
 
letter dated January 31, 2005 and May 25, 2005, respectively. The staff found this acceptable.
The staff identified that LRA Table 3.1.2.2, is not consistent with the GALL Report, Item IVB1.4-d, and asked the applicant for an explanation. By letter dated October 8, 2004, the
 
applicant submitted its formal response to the staff, stating that the GALL Report item should
 
have been IVB1.6-a instead of IVB1.4-d and the table will be corrected. The staff found this
 
acceptable because it is consistent with the GALL Report.
LRA Table 3.1.2.3, row 51, presents the AMR for the stainless steel valves in treated water internal environment for the reactor vessel v ents and drains systems. The staff identified a difference in crediting AMPs for this commodity group. The table includes the Chemistry Control
 
Program, BWR Stress Corrosion Cracking Program, and One-Time Inspection Program to
 
manage crack initiation and growth due to SCC, and cross-references LRA Table 3.1.1, Item 3.1.1.29. However, LRA Table 3.1.1, Item 3.1.1.29, does not specify the One-Time
 
Inspection Program. During the onsite audit, the staff asked the applicant to explain this
 
difference. By letter dated October 8, 2004, the applicant submitted its formal response to the
 
staff, stating that the One-Time Inspection Program will be removed from LRA Table 3.1.2.3, row 51. The staff found this acceptable because it is consistent with the GALL Report.
LRA Table 3.1.2.4, row 48, presents the AMR for the stainless steel fittings, including flow restrictors, in treated water internal environment for the reactor recirculation system. The staff
 
identified a difference in crediting AMPs for this commodity group. The table does not identify
 
the Chemistry Control Program to manage crack initiation and growth due to SCC. However, the
 
referenced GALL Report Item IV.C1.1-I identified the Chemistry Control Program. During the
 
onsite audit, the staff asked the applicant to explain this difference. By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the Chemistry Control
 
Program will be added to LRA Table 3.1.2.4, row 48. The staff found this acceptable because it
 
is consistent with the GALL Report.
On the basis of its audit, the staff determined that for AMRs not requiring further evaluation, as identified in LRA Table 3.1.1 (Table 1), the applicant's references to the GALL Report are
 
acceptable and no further staff review is required.
Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating
 
experience and proposals for managing associated aging effects. On the basis of its review, the 3-129 staff concluded that the AMR results, which the applicant claimed to be consistent with the GALL Report, are consistent with the AMRs in the GALL Report. Therefore, the staff concluded
 
that the applicant had demonstrated that the effects of aging for these components will be
 
adequately managed so that their intended function(s) will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended For some line items in LRA Tables 3.1.2.1 through 3.1.2.4 that are identified to be consistent with the GALL Report, the applicant cross-referenced specific line items in LRA Tables 3.1.1
 
through 3.4.1, for which the GALL Report recommends further evaluation. Where the GALL
 
Report recommends further evaluation, the staff reviewed the applicable further evaluations
 
provided in LRA Sections 3.1.2.2, 3.2.2.2, 3.3.2.2, and 3.4.2.2 against the criteria provided in
 
SRP-LR Sections 3.1.2.2, 3.2.2.2, 3.3.2.2, and 3.4.2.2, respectively. The following provides the
 
staff's assessment of the applicant's further evaluations applicable to the reactor vessel, internals, and reactor coolant system.
Summary of Technical Information in the Application. In LRA Section 3.1.2.2, the applicant provided further evaluation of aging management as recommended by the GALL Report for the reactor vessel, internals, and reactor coolant system components. The applicant provided
 
information concerning how it will manage the following aging effects:
* cumulative fatigue damage (3.1.2.2.1)
* loss of material due to general corrosion (3.1.2.2.2)
* loss of fracture toughness due to neutron irradiation embrittlement (3.1.2.2.3)
* crack initiation and growth due to thermal and mechanical loading or stress corrosion cracking (3.1.2.2.4)
* crack growth due to cyclic loading (3.1.2.2.5, PWR only)
* changes in dimension due to void swelling (3.1.2.2.6/PWR only)
* crack initiation and growth due to stress corrosion cracking or primary water stress corrosion cracking (PWSCC)(3.1.2.2.7/PWR only)
* crack initiation and growth due to stress corrosion cracking or irradiation assisted stress corrosion cracking(3.1.2.2.8/ PWR only)(3.1.2.2.8/PWR only)
* loss of preload due to stress relaxation(3.1.2.2.9/PWR only)
* loss of section thickness due to erosion (3.1.2.2.10/PWR only)
* crack initiation and growth due to PWSCC, outside-diameter stress corrosion cracking, or intergranular attack or loss of material due to wastage and pitting corrosion or loss of
 
section thickness due to fretting and wear or denting due to corrosion of carbon steel
 
tube support plate (3.1.2.2.11/PWR)
* loss of section thickness due to flow-accelerated corrosion (3.1.2.2.12/PWR) 3-130
* ligament cracking due to corrosion (3.1.2.2.13/PWR)
* loss of material due to flow accelerated corrosion (3.1.2.2.14/PWR)
* quality assurance for aging management of non-safety-related components Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends
 
further evaluation, the staff audited and reviewed the applicant's evaluation to determine
 
whether it adequately addressed the issues that were further evaluated. In addition, the staff
 
reviewed the applicant's further evaluations against the criteria contained in Section 3.1.2.2 of
 
the SRP-LR. Details of the staff's audit are documented in the staff's BFN audit and review
 
report. The staff's evaluation of the aging effects is discussed in the following sections.
3.1.2.2.1  Cumulative Fatigue Damage
 
For LRA Table 3.1.1, item 3.1.1.1, the applicant references LRA Section 3.1.2.2.1. This is a TLAA, and is evaluated in SER Section 4.
3.1.2.2.2  Loss of Material due to General Corrosion
 
The staff reviewed LRA Section 3.1.2.2.2 against the criteria in SRP-LR Section 3.1.2.2.2.
 
The SRP-LR identifies that the only BWR component covered by this further evaluation is the isolation condenser. This is not applicable because BFN does not have an isolation condenser.
3.1.2.2.3  Loss of Fracture Toughness Due To Neutron Irradiation Embrittlement
 
The staff reviewed LRA Section 3.1.2.2.3 against the criteria in SRP-LR Section 3.1.2.2.3.
 
Consistent with the SRP-LR, the applicant references LRA Section 4.2. This is a TLAA, and is evaluated in SER Section 4.
Also consistent with the SRP-LR, the applicant references the Reactor Vessel Surveillance Program, described in LRA Section B.2.1.28. This AMP is reviewed and evaluated in SER
 
Section 3.0.3.2.19.
The AMP recommended by the GALL Report for managing loss of fracture toughness due to neutron irradiation embrittlement of the RV is GALL AMP XI.M31, "RV Surveillance," which complies with the requirements of 10 CFR Part 50, Appendices G and H. Loss of fracture
 
toughness due to neutron irradiation embrittlement could occur in the RV. An RV materials
 
surveillance program monitors neutron irradiati on embrittlement of the RV. RV surveillance programs may be plant-specific, depending on matters such as the composition of limiting
 
materials, availability of surveillance capsules, and projected fluence levels or may be an ISP
 
based on the criteria in 10 CFR Part 50, Appendix H. In accordance with
 
10 CFR Part 50, Appendix H, an applicant is required to submit its proposed withdrawal
 
schedule for approval prior to implementation.
3-131 LRA Section 3.1.2.2.3 addresses (1) loss of fracture toughness due to neutron irradiation embrittlement for ferritic materials that have a neutron fluence of greater than 10 17 n/cm 2 at the end of the license renewal term, and (2) loss of fracture toughness due to irradiation
 
embrittlement of the RV beltline material. Loss of fracture toughness due to neutron irradiation
 
embrittlement for ferritic materials that have a neutron fluence of greater than 101 7 n/cm 2 at the end of the license renewal term is a TLAA, and the staff's review of the applicant's evaluation of
 
this TLAA is documented in LRA Section 4.2. In performing this review, the staff followed the
 
guidance in SRP-LR Section 4.2.
The RV Surveillance Program is mandated by 10 CFR Part 50, Appendix H. The RV Surveillance Program is an ISP in accordance with 10 CFR Part 50, Appendix H Paragraph III.C
 
that is based on requirements established by the BWRVIP. Referencing of BWRVIP activities
 
for license renewal was approved by the staff in its SER regarding BWRVIP-74 of October 18, 2001. The demonstration of compliance with the required actions of the SE is summarized in
 
LRA Section 3.1.2.2.16. The applicant stated that the RV Surveillance Program, as supported
 
by associated TLAA evaluations (LRA Section 4.2), will manage loss of fracture toughness of
 
RV beltline components due to irradiation embri ttlement by addressing the limiting RV beltline shells and welds.
The applicant also stated that the RV Surveillance Program is described in UFSAR Section 4.2.6 and is based on BWRVIP-78, "BWR Vessel Integrated Surveillance Program
 
Plan," and BWRVIP-86, BWR Vessel and Internal Project Updated BWR Integrated Surveillance
 
Program (ISP) Implementation Plan." Use of the BWRVIP-78 and BWRVIP-86 to address a
 
40-year license period was approved for referencing in the staff's SER dated February 1, 2000.
 
Use of the BWRVIP ISP for Units 2 and 3 was approved by the staff in its SER dated
 
January 28, 2003. The technical criteria specified in the BWRVIP-78 and BWRVIP-86 were
 
incorporated in the BWRVIP-116, "BWR Vessel and Internals Project-Integrated Surveillance
 
Program (ISP)-Implementation for License Renewal." BWRVIP-116 extends the ISP to cover
 
the BWR fleet through an extended period of operation for all units. The applicant committed to
 
implement the requirements of BWRVIP-116, w hen approved, for all three RVs. Therefore, the applicant did not submit a plant-specific program in its LRA. The details of the staff's review of
 
this aging effect are included in SER Section 3.0.3.2.
The applicant stated that it will implement the BWRVIP ISP for the period of extended operation, if approved by the staff for the BWR fleet, as applicable to each RV and will request the
 
approval from the staff, if necessary, to use the program at applicable RVs for the period of
 
extended operation. This enhancement is scheduled for completion prior to the period of
 
extended operation.
The staff found that by implementing the ISP pr ogram as dictated by the RV Surveillance Program, the applicant demonstrated that it complies with all the recommendations specified in GALL AMP XI.M31. Therefore, the staff accepted the implementation of the RV Surveillance
 
Program for managing the aging effect due to loss of fracture toughness due to neutron
 
irradiation embrittlement of the RVs.
Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluated AMR results involving management of loss of fracture toughness due to neutron irradiation
 
embrittlement as recommended in the GALL Report. Since the applicant's AMR results are
 
otherwise consistent with the GALL Report, the staff found that the applicant had demonstrated 3-132 that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
3.1.2.2.4  Crack Initiation and Growth due to Thermal and Mechanical Loading or Stress Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.4 against the criteria in SRP-LR Section 3.1.2.2.4.
 
LRA Table 3.1.2.3 and Table 3.1.2.4 present the AMRs for small bore piping and fittings (including flow restrictors) less than NPS 4 in treated-water environment for the RCS. These
 
AMRs reference LRA Table 1 Item 3.1.1.7, which references LRA Section 3.1.2.2.4 for the
 
further evaluation.
In the LRA Section 3.1.2.2.4, the applicant addressed the potential for crack initiation and growth due to thermal and mechanical loading or SCC (including IGSCC) that could occur in
 
small-bore RCS and connected system piping less than NPS 4.
SRP-LR Section 3.1.2.2.4 applicable to BFN (BWRs) states the following:
1.Crack initiation and growth due to thermal and mechanical loading or SCC (including IGSCC) could occur in small-bore reactor coolant system and connected system pipingless than NPS 4. The existing program relies on ASME Section XI ISI and on control of
 
water chemistry to mitigate SCC. The GALL Report recommends that a plant-specific
 
destructive examination or a nondestructive examination (NDE) that permits inspection of the inside surfaces of the piping be conducted to ensure that cracking has not
 
occurred and the component intended function will be maintained during the extended
 
period. The AMPs should be augmented by verify ing that service-induced weld cracking is not occurring in the small-bore piping less than NPS 4, including pipe, fittings, and
 
branch connections. A one-time inspection of a sample of locations is an acceptable
 
method to ensure that the aging effect is not occurring and the component's intended
 
function will be maintained during the period of extended operation. 2.Crack initiation and growth due to thermal and mechanical loading or SCC (including IGSCC) could occur in BWR reactor vessel flange leak detection line and BWR jet pump
 
sensing line. The GALL Report recommends that a plant-specific AMP be evaluated to
 
mitigate or detect crack initiation and growth due to SCC of vessel flange leak detection
 
line. Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this standard review plan).
The applicant should verify that service-induced weld cracking is not occurring in small-bore piping less than NPS 4. A one-time inspection of a sample of locations is an acceptable method
 
to ensure that the aging effect is not occurring and the component's intended function will be maintained during the period of extended operation. Per ASME Code Section XI, 1995 Edition, Examination Category B-J or B-F, small bore piping (defined as piping less than NPS 4), does
 
not receive volumetric inspection.
The BFN-proposed One-Time Inspection Program includes volumetric examination of a sample of susceptible locations in small bore piping and pipe fittings. During the onsite audit, which took 3-133 place the weeks of June 21 and July 26, 2004, the staff asked the applicant to explain the selection criteria for these sample locations. In its response, the applicant stated:
The one-time inspections utilized to verify the effectiveness of the Chemistry Control Program for preventing loss of material will select the susceptible locations based on
 
plant operating experience, with an emphasis on locations that potentially have low or
 
stagnant flow conditions.
 
The staff expanded the question in a subsequent teleconference with the applicant. In
 
response, the applicant stated:
The BFN One-Time Inspection Program includes a sample inspection of Reactor
 
Coolant Pressure (RCPB) Boundary piping less than four inch NPS exposed to reactor
 
coolant for cracking.
The Browns Ferry One-Time Inspection Program provides the following description of how cracking will be detected.
The inspection includes a representative sample of the system population, and, where practical, focuses on the bounding or lead components most susceptible
 
to aging due to time in service, severity of operating conditions, and lowest
 
design margin. For small-bore piping, actual inspection locations are based on
 
physical accessibility, exposure levels, NDE techniques, and locations identified
 
in Nuclear Regulatory Commission (NRC) Information Notice (IN) 97-46.
Combinations of NDE, including visual, ultrasonic, and surface techniques, are performed by qualified personnel following procedures consistent with the ASME
 
Code and 10 CFR 50, Appendix B. For small-bore piping less than NPS 4 in.,
including pipe, fittings, and branch connections, a plant-specific destructive
 
examination of replaced piping due to plant modifications or NDE that permits
 
inspection of the inside surfaces of the piping is to be conducted to ensure that
 
cracking has not occurred. Follow-up of unacceptable inspection findings
 
includes expansion of the inspection sample size and locations.
The inspection and test techniques prescribed by the program verify any aging effects because these techniques, used by qualified personnel, have been
 
proven effective and consistent with staff expectations. With respect to inspection
 
timing, the one-time inspection is to be completed before the end of the current
 
operating license. The applicant may schedule the inspection in such a way as to
 
minimize the impact on plant operations. However, the inspection is not to be
 
scheduled too early in the current operating term, which could raise questions
 
regarding continued absence of aging effects prior to and near the extended
 
period of operation.
In its letter, dated October 8, 2004, in response to the staff's question, the applicant stated: ... Aging Management Program XI.M32, One-Ti me Inspection, Evaluation and Technical Basis Section, Detection of Aging Effects, states:
3-134 Combinations of NDE, including visual, ultrasonic, and surface techniques, are performed by qualified personnel following procedures consistent with the ASME
 
Code and 10 CFR 50, Appendix B. For small-bore piping less than NPS 4 in.,
including pipe, fittings, and branch connections, a plant-specific destructive
 
examination of replaced piping due to plant modifications or NDE that permits
 
inspection of the inside surfaces of the piping is to be conducted to ensure that
 
cracking has not occurred.
As noted from this paragraph, either destructive examination or NDE that is capable of detecting inside surface cracking is required. Since there are UT-inspectable, full
 
penetration butt welds within scope of license renewal, BFN has chosen the second
 
method for our program and no destructive examination of socket welds will be
 
performed. Once this inspection methodology was selected, the possible sample
 
population is full penetration butt welds. BFN has no identified butt welds in ASME
 
Class 1 piping 1-inch NPS and less. Therefore, 1-inch NPS and less piping will not be
 
selected for small-bore piping NDE E-67 examination. This sample population provides
 
adequate indication of whether inside diameter cracking is occurring in small-bore
 
piping.The staff disagreed with the applicant's response in that socket-welded piping, 1-inch NPS and less, is adequately represented by the applicant's sample selection criteria for small bore piping
 
included in the scope of the One-Time Inspection Program. The staff disputed that, historically, piping 1-inch NPS and less, is more susceptible to failure. The geometry of and joining methods
 
for socket welds make them more susceptible to cracking than full penetration butt welds. But, the staff would be willing to accept NDE of full penetration butt welds in piping greater than
 
1-inch NPS as being representative of socket-welded piping, 1-inch NPS and less.
In RAI 3.1.2.4-7, dated March 11, 2005, the staff questioned why the applicant was not complying with the GALL Report recommendation that a plant-specific destructive examination
 
or a nondestructive examination (NDE) that permits inspection of the inside surfaces of the
 
piping be conducted to ensure that cracking has not occurred and the component intended
 
function will be maintained during the extended period.
In its response, dated April 5, 2005, the applicant stated that:
The One-Time Inspection Program will evaluate a sample of welds in small-bore piping less than 4 inches NPS for internal surface cracking by NDE as specified by NUREG-1800, Aging Management Program XI.M32, "One-Time Inspection." The BFN
 
One-Time Inspection Program sample will be selected from full penetration butt welds
 
where ultrasonic testing can be performed. The basis for this sample population is:
* this sample will evaluate the welds with the most susceptibility to the aging effects of stress corrosion cracking and thermal fatigue;
* this sample will evaluate the welds with the most significant consequences and risks; and
* this sample will allow the welds to be identified, scheduled, and performed in a systematic manner.
3-135 Socket weld cracking generally occurs due to weld defect propagation by vibrational fatigue. Stress corrosion cracking and thermal fatigue rarely cause socket weld failures.
 
Vibration induced socket weld failures is a design issue that has been observed in the
 
nuclear power industry and can result in crack initiation and growth. Vibration induced
 
fatigue is fast acting and is typically detec ted early in a component's life. Corrective measures typically include actions to preclude recurrence of the failure mechanism.
 
Corrective actions to preclude recurrence may involve modifications to the plant, such as
 
addition of supplemental restraints to a piping system, shortening the vent piping, replacement of tubing with flexible hose, etc. Based upon these measures, cracking due
 
to vibration-induced fatigue is not considered an aging effect for the period of extended
 
operation.
Previously, plants have excluded piping based strictly on consequences of the potential pipe failure. Although this was not done in the BFN Risk Informed ISI Program, a plant
 
specific calculation demonstrates that BFN can tolerate 2-inch NPS and smaller breaks
 
with normal makeup. At BFN, all Class 1 piping was included in the BFN Risk Informed
 
ISI Program. No welds less than 4 inches NPS were identified as high risk. The BFN
 
One-Time Inspection Program sample will select full penetration butt welds where
 
ultrasonic testing can be performed. The butt welds are more susceptible to stress
 
corrosion cracking and thermal fatigue, which are the primary crack initiation and growth
 
aging mechanisms. This sample also allows a selection of the most risk-significant
 
small-bore piping locations (i.e., locations with the highest susceptibility to cracking and
 
highest consequences of failure) to be identified, scheduled, and performed in a
 
systematic manner, rather than attempting to track modifications for 20 years while awaiting the possible removal of a piece of small-bore piping containing a weld for
 
destructive testing.
The staff evaluated the applicant's response and concurred with the evaluation. Therefore, the staff's concern described in RAI 3.1.2.4-7 is resolved.
The staff also asked the applicant where GALL Report Volume 1, Table 1, Item 3.1.1.8, jet pump sensing line and reactor vessel flange detection line, as stated in LRA Section 3.1.2.2.4, are addressed in the AMR. By letter dated October 8, 2004, the applicant submitted its formal
 
response to the staff. The applicant stated:
GALL Volume 1, Table 1, Item 3.1.1.8 states that the corresponding GALL Volume 2 line items are IV.A1.1-d and IV.B1.4-d.
GALL Volume 2, Line IV.A1.1-d:
The Browns Ferry top head enclosure - vessel flange leak detection line is not consistent with GALL Volume 2, Line IV.A1.1-d. The Browns Ferry components included in this line
 
item are carbon and low-alloy steel, whereas GALL Volume 2, Line IV.A1.1-d refers to
 
stainless steel. The components included in this line item are the penetration through the
 
carbon steel vessel flange and a short segment of carbon steel piping and fittings
 
external to the reactor vessel. Therefore this line was not shown as corresponding to
 
GALL Volume 1, Table 1, Item 3.1.1.8.
Currently, One-Time Inspection is listed as the aging management program for this line item. The Browns Ferry reactor vessel flange leak detection line is ASME Class 2 3-136Equivalent and should have included the ASME Section XI Subsections IWB, IWC and IWD Inservice Inspection Program as an aging management program. ASME Section XI Subsections IWB, IWC and IWD Inservice Inspection Program will be added to this line
 
item.The remaining portion of the vessel flange leak detection line is stainless steel. This stainless steel piping is in the Feedwater System (003) at Browns Ferry. Aging of this
 
piping is addressed in Table 3.4.2.3 and corresponds to GALL, Volume 2, Item C1.1-i, piping and fittings - small bore piping less than NPS 4.
GALL Volume 2, Line IV.B1.4-d:
The Browns Ferry jet pump assemblies - jet pump sensing line is not consistent with GALL Volume 2, Line IV.B1.4-d. Section IV.B1 addresses BWR reactor vessel internals.
 
The jet pump sensing lines internal to the reactor vessel have been determined to not be
 
within the scope of license renewal for Browns Ferry. Therefore this line was not shown
 
as corresponding to GALL Volume 1, Table 1, Item 3.1.1.8.
The jet pump instrumentation penetration is stainless steel clad carbon steel and is included with GALL Volume 2, Line IV.A1.5-a, Penetrations. External to the reactor
 
vessel, the stainless steel jet pump sensing lines are included in GALL, Volume 2, Item
 
C1.1-i, piping and fittings - small bore piping less than NPS 4.
In a follow-up response to the staff's question, the applicant provided the following ARM table information:Jet Pump
* Internal to RV - not in scope
* Penetration - Table 3.1.2.1, Items 63, 64, and 65
* External to RV - Table 3.4.2.3, Items 40 and 41 RV flange leak detection line
* Penetration - Table 3.1.2.1, Item 9
* External to RV - Table 3.1.2.4, Items 88, 89, and 90 The staff found the response acceptable on the basis that the applicant had adequately described its AMR for the jet pump and RV flange leak detection line, and also identified an
 
appropriate correction to the AMR for the RV flange leak detection line.
During the onsite audit, the staff asked the applicant a question related to proposed AMPs for cracking of small bore piping due to cyclic loading. GALL Report Volume 1, Table 1, Item
 
3.1.1.7 identifies the Chemistry Control, the One-Time Inspection, and the ASME ISI Programs
 
for managing this aging effect. However, the applicant has not included the Chemistry Control
 
Program as one of the proposed AMPs. By letter dated October 8, 2004, the applicant
 
submitted its formal response to the staff, stating:
GALL Volume 1, Table 1 specifies that consistency with GALL Volume 2, Line IV.C1.1-i establishes consistency with GALL Volume 1, Table 1, Item 3.1.1.7. Previous to the
 
Browns Ferry LRA, all license renewal applications have been written at the aging effect
 
level and did not address aging mechanisms. The primary difficulty in determining GALL
 
line item consistency is that the aging management programs should be consistent with 3-137 the aging effects listed, not necessarily with the individual aging mechanisms listed.
Therefore when reviewing the aging mechanism "crack initiation/growth due to cyclic
 
loading" instead of the aging effect "crack initiation/growth," some interpretation of the
 
GALL line item was required.
GALL Report Item IV.C1.1-i addresses specific concerns with small bore piping and fittings less than NPS 4. The GALL line item provides a comprehensive listing of
 
potential aging mechanisms and aging management programs for the crack initiation and growth agingeffect. To address that all materials and aging management
 
programs are not applicable to each aging mechanism, this GALL line item was
 
interpreted follows for the various materials and aging mechanisms.
Stainless steel/Treated water (Note 1)
Aging Effect
* Crack initiation and growth/ Stress corrosion cracking, inter-granular stress corrosion cracking Aging Management Programs
* ASME Section XI Subsections IWB, IWC and IWD Inservice Inspection Program (B.2.1.4)
* Chemistry Control Program (B.2.1.5)
* One-Time Inspection Program (B.2.1.29)
Stainless steel/Treated water (Note 2)
Aging Effect
* Crack initiation and growth/ Thermal and mechanical loading
 
Aging Management Programs
* ASME Section XI Subsections IWB, IWC and IWD Inservice Inspection Program (B.2.1.4)
* One-Time Inspection Program (B.2.1.29)
Carbon steel/Treated water (Note 3)
Aging Effect
* Crack initiation and growth/ Stress corrosion cracking, inter-granular stress corrosion cracking Aging Management Programs
* None Carbon steel/Treated water (Note 4)
Aging Effect
* Crack initiation and growth/ Thermal and mechanical loading 3-138 Aging Management Programs
* ASME Section XI Subsections IWB, IWC and IWD Inservice Inspection Program (B.2.1.4)
* One-Time Inspection Program (B.2.1.29)
NOTES:  1.For crack initiation and growth due to stress corrosion cracking and inter-granular stress corrosion cracking of stainless steel, the three aging management
 
programs included in GALL line item IV.C1.1-i are applicable and are specified
 
by the Browns Ferry LRA. 2.For crack initiation and growth due to thermal and mechanical loading of stainless steel, continued application of cyclic stresses can produce crack growth
 
once a crack or crack-like flaw has initiated. This is a purely mechanical function
 
and is not managed or mitigated by the Chemistry Control Program. The purpose
 
of these examinations is to identify flaws that may lead to unstable crack growth
 
in the pressure boundary during service. The welds in the piping and fittings are
 
basically the same material as one or both of the parts being joined and are
 
regarded as having higher potential for flaws than base material to experience flaw growth during plant operation. Therefore, the ASME Section XI Subsections
 
IWB, IWC and IWD Inservice Inspection Program focuses on welds and a One-Time Inspection Program augments the ASME Section XI Subsections IWB, IWC and IWD Inservice Inspection Program for verifying that service-induced
 
cracking is not occurring in the small-bore piping less than NPS 4. 3.For crack initiation and growth due to stress corrosion cracking and inter-granular stress corrosion cracking of carbon and low-alloy steels, no aging management
 
programs are applicable as carbon and low-alloy steels are not susceptible to
 
stress corrosion cracking in this application. 4.For crack initiation and growth due to thermal and mechanical loading of carbon and low-alloy steels, continued application of cyclic stresses can produce crack
 
growth once a crack or crack-like flaw has initiated. This is a purely mechanical
 
function and is not managed or mitigated by the Chemistry Control Program. The
 
purpose of these examinations is to identify flaws that may lead to unstable crack
 
growth in the pressure boundary during service. The welds in the piping and
 
fittings are basically the same material as one or both of the parts being joined
 
and are regarded as having higher potential for flaws than base material to experience flaw growth during plant operation. Therefore, the ASME Section XI
 
Subsections IWB, IWC and IWD Inservice Inspection Program focuses on welds and a One-Time Inspection Program augments the ASME Section XI
 
Subsections IWB, IWC and IWD Inservice Inspection Program for verifying that
 
service-induced cracking is not occurring in the small-bore piping less than
 
NPS 4.The staff found the applicant's basis for not crediting the Chemistry Control Program to beappropriate and acceptable. The GALL Report specifies AMP XI.M1, "ASME Section XI
 
Inservice Inspection, Subsections IWB, IWC, and IWD," to detect crack initiation and growth in components, and AMP XI.M2, "Water Chemistry," to mitigate crack initiation and growth due to 3-139SCC. The GALL Report further specifies AMP XI.M32, "One-Time Inspection," as an acceptable method to verify that cracking is not occurring in small bore piping. Since cracking due to cyclic
 
loading is caused by mechanical or thermal loads, as opposed to an adverse chemical
 
environment, the staff accepted the applicant's basis for not crediting the Chemistry Control
 
Program as an AMP for managing cracking due to cyclic loading. The applicant appropriately
 
credited the Chemistry Control Program to mitigate crack initiation and growth due to SCC.
On the basis of its review of the scope of Chemistry Control Program, One-Time Inspection Program, and the ASME ISI Program, the staff f ound that the applicant appropriately evaluated AMR results involving management of crack initiation and growth due to thermal and
 
mechanical loading and SCC, consistent with the recommendations in the GALL Report.
3.1.2.2.5  Crack Growth due to Cyclic Loading
 
Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3.1.2.2.6  Changes in Dimension due to Void Swelling
 
Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3.1.2.2.7  Crack Initiation and Growth due to Stress Corrosion Cracking or Primary Water Stress Corrosion Cracking Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3.1.2.2.8  Crack Initiation and Growth due to Stress Corrosion Cracking or Irradiation Assisted Stress Corrosion Cracking Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3.1.2.2.9  Loss of Preload due to Stress Relaxation
 
Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3.1.2.2.10  Loss of Section Thickness due to Erosion
 
Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3.1.2.2.11  Crack Initiation and Growth due to Primary Water Stress Corrosion Cracking, Outside-Diameter Stress Corrosion Cracking, or Intergranular Attack or Loss of Material due to
 
Wastage and Pitting Corrosion or Loss of Section Thickness due to Fretting and Wear or
 
Denting due to Corrosion of Carbon Steel Tube Support Plate 3-140 Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3.1.2.2.12  Loss of Section Thickness due to Flow Accelerated Corrosion
 
Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3.1.2.2.13  Ligament Cracking due to Corrosion
 
Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3.1.2.2.14  Loss of Material due to Flow Accelerated Corrosion
 
Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3.1.2.2.15  Quality Assurance for Aging Management of Non-Safety-Related Components The applicant referenced LRA Section B.1.3. The staff's evaluation of LRA Section B.1.3 is provided in SER Section 3.0.4.
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report
 
recommends further evaluation, the staff determined that (1) those attributes or features for
 
which the applicant claimed consistency with the GALL Report were indeed consistent, and (2)
 
the applicant had adequately addressed the issues that were further evaluated. The staff found
 
that the applicant demonstrated that the effects of aging will be adequately managed so that the
 
intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).3.1.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.1.2.1 through 3.1.2.4, the staff reviewed additional details of the results of the AMRs for material, environment, aging
 
program (MEAP) combinations that are not consistent with the GALL Report, or that are not
 
addressed in the GALL Report.
In LRA Tables 3.1.2.1 through 3.1.2.4, the applicant indicated, via Notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a
 
line item in the GALL Report, and provided inform ation concerning how the aging effect will be managed. Specifically, Note F indicated that the material for the AMR line item component is not
 
evaluated in the GALL Report. Note G indicated that the environment for the AMR line item
 
component and material is not evaluated in the GALL Report. Note H indicated that the aging
 
effect for the AMR line item component, materi al, and environment combination is not evaluated in the GALL Report. Note I indicated that the aging effect identified in the GALL Report for the
 
line item component, material, and environment combination is not applicable. Note J indicated 3-141 that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.
Staff Evaluation. For component type, material, and environment combinations that are not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine
 
whether the applicant had demonstrated that the effects of aging will be adequately managed
 
so that the intended function(s) will be maintained consistent with the CLB during the period of
 
extended operation. The staff's evaluation is discussed in the following sections.
During the onsite audit, the staff reviewed selected AMR results in LRA Tables 3.1.2.1 through 3.1.2.4, for MEAP combinations that are not consistent with the GALL Report.
3.1.2.3.1  Reactor Vessel - Summary of Aging Management Evaluation - Table 3.1.2.1
 
The staff reviewed LRA Table 3.1.2.1, which summarizes the results of AMR evaluations for the component groups.
During the onsite audit, the reactor vessel components evaluated by the staff were the reactor vessel attachment welds, the reactor vessel closure studs and nuts, the reactor vessel support
 
skirt and attachment welds, the refueling bellows support skirt, and the stabilizer bracket.
The staff reviewed LRA Table 3.1.2.1, which summarizes the results of the applicant's AMR evaluations for the reactor vessel pressure boundary component groups.
The onsite audit scope for the reactor vessel components did not include any MEAP combinations that are not consistent with the GALL Report.
For the carbon and low-alloy steel components (reactor vessel support skirt and attachment welds, the refueling bellows support skirt, and the stabilizer bracket), exposed externally to
 
inside air of the containment, the applicant identified cracking due to fatigue as a TLAA. TLAAs
 
are evaluated in SER Section 4.
3.1.2.3.2  Reactor Vessel Internals - Summary of Aging Management Evaluation -
Table 3.1.2.2 The staff reviewed LRA Table 3.1.2.2, which summarizes the results of AMR evaluations for the reactor vessel internals component groups.
In LRA Table 3.1.2.2, the applicant's AMR for almost all the RVI components is consistent with the GALL Report. In addition, the applicant has identified several stainless steel and nickel-alloy
 
RVI components (i.e., core shroud and core plate, top guide, spray lines and spargers, fuel
 
support, CRD housing, and dry tubes and guide tubes), in a treated-water environment, as
 
being subject to loss of material due to crevice and pitting corrosion; this is not addressed in the
 
GALL Report. To manage this aging effect, the applicant credits the BWR Vessel Internals
 
Program, and Chemistry Control Program. The sta ff accepted the Chemistry Control Program to minimize the potential for loss of material in these components. The BWR Vessel Internals
 
Program would detect any loss of material, if it is occurring. The BWR Vessel Internals Program
 
includes BWRVIP recommendations for an effective inservice inspection of reactor vessel
 
internal components.
3-142 In LRA Table 3.1.2.2, the applicant credits the BWR Vessel Internals Program and Chemistry Control Program to manage cracking in nickel-alloy components of the core spray lines and
 
sparger assembly, and the stainless steel fuel supports. The staff found that the applicant will
 
manage cracking in a manner consistent with the GALL Report.
In LRA Table 3.1.2.2, the applicant identified no aging effect for (1) stainless steel CRD housing external surfaces exposed to containment air and (2) stainless steel dry tube/guide tube internal
 
surfaces exposed to air/gas. Air is not identified in the GALL Report as an environment for these
 
components and materials. On the basis of current industry research and operating experience, an internal/external environment of gas (which is similar to dry air) on metal will not result in
 
aging that will be of concern during the period of extended operation. Therefore, the staff
 
concluded that there are no applicable aging effects for stainless steel in a gas environment.
The staff found that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.3.3  Reactor Vessel Vents and Drains System - Summary of Aging Management Evaluation - Table 3.1.2.3 The staff reviewed LRA Table 3.1.2.3, which summarizes the results of AMR evaluations for the reactor vessel internals component groups.
In LRA Table 3.1.2.3, the applicant included pressure boundary components (i.e., piping, pipe fittings, and valves) for vents and drains associated with the RCS. The GALL Report includes
 
some of these RCS components as part of t he steam and power conversion systems in GALL Report Chapter VIII. Most of these components are made of either carbon/low-alloy steel or
 
stainless steel, and are exposed to air/gas, inside air, or treated-water environment.
The applicant identified no aging effects for stainless steel components exposed to an internal environment of air/gas for piping and fittings, or for carbon/low-alloy steel components exposed to inside air greater than 212 °F on external surfaces. Gas is not identified in the GALL Report
 
as an environment for these components and materials. On the basis of current industry
 
research and operating experience, the staff concluded that an internal environment of gas (which is similar to dry air) on stainless steel components will not result in aging that will be of
 
concern during the period of extended operation, and found that the applicant's AMR is
 
acceptable for stainless steel exposed to a gas environment. For carbon/low-alloy steel components exposed to inside air greater than 212 °F on external surfaces, the staff found that
 
the applicant's AMR is acceptable, because the high environmental temperature precludes the
 
presence of moisture on the external surfaces.
The applicant proposes to manage loss of material of carbon steel piping and valve component groups exposed to air/gas using the One-Time Inspection Program, which is a new
 
plant-specific program. Visual inspections of the internal surfaces of plant components and plant
 
commodities are performed during the performance of maintenance to determine loss of
 
material. The staff found that the One-Time Inspection Program is acceptable for managing loss
 
of material due to general corrosion since visual inspection will be performed on internal
 
surfaces of components to detect any sign of aging degradation.
3-143 In LRA Table 3.1.2.3, the applicant identified the Flow-Accelerated Corrosion Program, to manage loss of material due to flow accelerated corrosion in piping and fittings made of
 
carbon/low-alloy steel. This program includes analysis to determine critical locations, baseline
 
inspections to determine the extent of thinning at these locations, and follow-up inspections to
 
confirm the predictions. Repair, replacements, or re-evaluations are performed as necessary.
 
The staff found that the applicant identified the appropriate AMP for this aging effect.
In LRA Table 3.1.2.3, the applicant identified that loss of material due to general, crevice, pitting and galvanic corrosion in both carbon/low-alloy steel and stainless steel piping and fittings in the
 
reactor vessel vents and drains lines is managed by the Chemistry Control Program and One-Time Inspection Program. The Chemistry C ontrol Program relies on monitoring and control of reactor water chemistry based on BWRVIP-79 to prevent loss of material from general, pitting, crevice or galvanic corrosion. However, high concentrations of impurities at crevices and
 
locations of stagnant flow conditions could cause corrosion. Therefore, verification of the
 
effectiveness of the Chemistry Control Program needs to be performed to ensure that corrosion is not occurring. The one-time inspection of selected components at susceptible locations is an
 
acceptable method for ensuring that corrosion is not occurring and that the component's
 
intended function will be maintained during the period of extended operation.
In RAI 3.1.2.3-1, dated December 1, 2004, the staff stated that, in LRA Table 3.1.2.3, the applicant identified loss of bolting function (loss of material) as an applicable aging effect due to
 
wear. The bolting is exposed externally to the inside air environment and the applicant credited its Bolting Integrity Program with management of this aging effect. Therefore, the staff
 
requested that the applicant provide information on the scope and techniques of past
 
inspections, the results obtained, applied mitigative methods, repairs, frequency of the
 
inspections, and any other relevant information.
In its response, by letter dated January 31, 2005, the applicant stated that bolting degradation due to wear could occur at locations of repeated relative motion of mechanical component
 
bolted joints. Wear of bolted joint components is generally not a concern as demonstrated by
 
industry operation experience and is not an AERM for the period of extended operation. For
 
license renewal purposes only, wear is assumed as a potential mechanism for critical bolting
 
applications. Critical bolting applications constitute RCPB components where closure bolting
 
failure could result in loss of reactor coolant and jeopardize safe operation of the plant.
 
The staff concurred with the applicant's identification of loss of bolting function due to wear in
 
carbon and low-alloy steel and stainless steel bolting associated with GALL Report Items
 
IV.C1.3-e and IV.C1.2-d. For those components that fall under the GALL Report Item IV.C1.2-d, the applicant indicated that the material listed in the GALL Report is different from the material
 
used at BFN (LRA Table 3.1.2.4, Footnote F). The applicant stated that the bolting used for
 
recirculation pump closure bolting is ASTM A540 Grade B23. Although the GALL Report lists
 
high-strength low-alloy (HSLA) steel SA-193 Grade B7 for the applicable component, the staff
 
concludes that degradation due to wear of ASTM A540 Grade B23 bolting will be adequately
 
managed by the applicant's Bolting Integrity Program and is acceptable. Therefore, the staff's
 
concern described in RAI 3.1.2.3-1 is resolved.
The staff found that the applicant demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
3-144 3.1.2.3.4  Reactor Vessel Recirculation Syst em - Summary of Aging Management Evaluation -
Table 3.1.2.4 The staff reviewed LRA Table 3.1.2.4 and Section 3.1.2.1.4. which summarize the results of AMR evaluations for the reactor recirc ulation system component groups. The component groups for this system include piping and fittings (including flexible connections, flow restricting
 
orifices and strainers), valves, pumps, tanks, and heat exchangers. The bolting group in thissystem is not part of the onsite audit scope.
In LRA Table 3.1.2.4, the applicant identified no aging effects in reactor recirculation component groups, for stainless steel and copper alloy carrying air/gas; for carbon/low-alloy steel, glass (fittings), and stainless steel, with external surface exposed to inside air; and for cast
 
iron/cast-iron alloys, carbon/low-alloy steel, copper alloys, glass (fittings), and stainless steel
 
carrying lubricating oil. Air and lubricating oil are not identified in the GALL Report as
 
environments for these components and materials.
Those components carrying lubricating oil are not subject to wetting and their surfaces always remain oil-coated because they are
 
continuously in service.
During the onsite audit, the staff asked the applicant if there exists any contamination of water in the components that carry lubricating oil. By letter dated October 8, 2004, the applicant
 
submitted its formal response to the staff, stating that:
Lubricating oil systems generally do not su ffer appreciable degradation by cracking or loss of material since the environment is not conducive to corrosion mechanisms. In
 
addressing the question, "Is there a potential for water contamination?" plant experience (i.e., maintenance/ operating history) is utilized as a basis for conclusions reached. The
 
lubricating oil applications where there is no history of water contamination do not have
 
any potential aging mechanisms. Those applications where water contamination does
 
occur, such as the diesel generator combustion air intake filters, potential loss of
 
material due to general, pitting, and crevice corrosion was identified as requiring
 
management for the period of extended operation.
Based on the applicant's response, the staff concluded that the applicant had appropriately addressed the lubricating oil environment in it s AMR. Those components that are susceptible to such contamination are identified, and aging management for loss of material is specified.
On the basis of current industry research and operating experience, dry air on metal will not result in aging that will be of concern during the period of extended operation. The external
 
environments being referred to are typical of ambient air (e.g., under a shelter, indoors, or
 
air-conditioned enclosure or room). Significant corrosion of low-alloy steel requires an
 
electrolytic environment, and a simultaneous presence of oxygen and moisture. Without the
 
presence of an aggressive environment, thes e components will experience insignificant amounts of corrosion, and no aging effects are applicable to this component/commodity group.
 
Wrought austenitic stainless steels are not susceptible to significant general corrosion that
 
would affect the intended function of components. Therefore, the staff concluded that there are
 
no applicable aging effects for these material and environment combinations.
3-145 In components made from cast iron, copper alloy, copper-zinc alloys, brass, ductile iron, and bronze, selective leaching takes place when these components are exposed to raw water, corrosion-inhibited treated water, oxygenated and de-oxygenated treated water, or are buried
 
underground. In LRA Table 3.1.2.4, the applicant identified the Selective Leaching of Materials
 
Program to manage loss of material due to selective leaching in copper-alloy components
 
associated with heat exchangers and tubing, valves, and pipe fittings exposed to raw water and
 
treated water. The applicant's selective leaching program relies on visual inspections and
 
hardness measurements of selected components susc eptible to selective leaching. On the basis of industry operating experience with this material and environment, the staff found this
 
acceptable.
Cast iron/cast-iron alloy fittings exposed to air/gas, carbon/low-alloy steel piping/fittings and valves exposed to air/gas, and stainless steel components of heat exchangers exposed to raw water (potable) or treated water are susceptible to loss of material due to pitting, crevice and
 
general corrosion, biofouling, and MIC. In LRA Table 3.1.2.4 (rows 60, 63, 65, and 66), the
 
applicant credited the One-Time Inspection Program to manage loss of material in these
 
components. This aging effect is not in the GALL Report for this component, material, and
 
environment combination. The one-time inspection pr ovides the opportunity to visually inspect the internal surfaces of components during preventive and corrective maintenance activities.
During the onsite audit, the staff noted corrosion, biofouling, and MIC in stainless steel and copper components in heat exchangers exposed to raw water or treated water that are
 
managed by One-Time Inspection Program. The staff asked if there were any other AMPs that periodically inspect heat exchangers subject to these aging mechanisms. By letter dated
 
October 8, 2004, the applicant submitted its formal response to the staff as follows:
For Table 3.1.2.4, Reactor Recirculation System, the raw water is supplied from the Raw Cooling Water System and should specify the Open-Cycle Cooling Water Program as the appropriate aging management program.
For Table 3.1.2.4, Reactor Recirculation System, the treated water refers to a self-contained cooling water system supplied with the Variable Frequency Drives. The
 
Chemistry Control Program and the One-Ti me Inspection Program are the appropriate aging management programs for this cooling water system.
The staff concurred that the Open-Cycle Coo ling Water Program for heat exchangers exposed to raw water and the Chemistry Control Program/One-Time Inspection Program for heat
 
exchangers exposed to treated water are the appropriate AMPs. These programs are able to
 
manage the aging effects due to corrosion, biofouling, and MIC in these components.
Cast iron/cast iron-alloy component external su rfaces exposed to inside air are managed by the Systems Monitoring Program against any loss of material due to general corrosion. The system walkdown encompasses all or part of the total acce ssible system, such that the entire system is covered over time. The walkdown is a detailed look at system parameters, material condition, operation, configuration, degraded components, outstanding work activities, and design
 
changes. The material condition involves no missing, discolored-indicating-a-potential-leak, or
 
damaged insulation. The staff found that the Sy stems Monitoring Program would be able to detect any corrosion on the external surfaces of these components.
3-146 In LRA Table 3.1.2.4, heat exchanger components made of carbon/low-alloy steel and exposed to raw water are susceptible to loss of material due to biofouling, MIC, crevice, galvanic, general, and pitting corrosion. The applicant credited the Open-Cycle Cooling Water System
 
Program to manage these aging effects. These AMP activities, in accordance with the
 
guidelines of GL 89-13, include managing aging effects by condition monitoring (system and
 
component testing, visual inspections, and NDE testing), and by preventive actions (biocide
 
treatment and filtering to prevent loss of material due to MIC, biofouling, flow blockage and
 
reduction of heat transfer due to biological and particulate fouling). The staff found this
 
acceptable.
In LRA Table 3.1.2.4, the applicant identified that the loss of material due to general, crevice, pitting, and galvanic corrosion in both carbon/low-alloy steel and stainless steel piping and
 
fittings and crack initiation/growth due to SCC in stainless steel piping and fittings in treated
 
water are managed by the Chemistry Control Program and One-Time Inspection Program. The Chemistry Control Program relies on monitoring and control of reactor water chemistry based on
 
BWRVIP-79 to prevent loss of material from general, pitting, crevice or galvanic corrosion.
However, high concentrations of impurities at crevices and locations of stagnant flow conditions
 
could cause corrosion. Therefore, verification of the effectiveness of the Chemistry Control
 
Program needs to be performed to ensure that corrosion is not occurring. The one-time
 
inspection of selected components at susceptible locations is an acceptable method for
 
ensuring that corrosion is not occurring and that the component's intended function will be
 
maintained during the period of extended operation.
In LRA Table 3.1.2.4, the applicant identified loss of bolting function due to wear as an AERM for carbon, low-alloy, and stainless steel components that are exposed externally to the inside
 
air environment. The applicant's AMR for these components has categorized them as one of the
 
following: 1) Material not in the GALL Report item for this component (i.e., LRA Table 3.1.2.4, Footnote F), or 2) Consistent with the GALL Report item for component, material, environment, and aging effect. The AMP takes some exception to GALL (i.e., LRA Table 3.1.2.4, Footnote B).
 
The applicable bolting is the RCPB valve closure bolting (GALL Report Item IV.C1.3-e) and
 
reactor recirculation pump closure bolting (GALL Report Item IV.C1.2-d). The applicant credits
 
the Bolting Integrity Program in LRA Section B.2.1.16 with the management of loss of bolting
 
function due to wear of the aforementioned carbon and low-alloy steel and stainless steel bolts.
In RAI 3.1.2.3-1(C), dated December 16, 2004, the staff stated that the LRA identified loss of bolting function (loss of material) as an applicable aging effect due to wear. The bolting is
 
exposed externally to the inside air environment and the applicant credited its Bolting Integrity Program with management of this aging effect. Therefore, the staff requested that the applicant provide information as to how the plant-specific experience related to this aging effect impacts
 
the attributes specified in the Bolting Integrity Program. In response to RAI 3.1.2.3-1(C), by
 
letter dated January 31, 2005, the applicant provided the following summary of its aging effect
 
evaluation for wear.
Bolting degradation due to wear could potentially occur at locations of repeated relative motion of mechanical component bolted joints. Wear of bolted joint components is
 
generally not a concern; however, for license renewal purposes, wear is being assumed
 
as a potential mechanism for 'critical bolting applications.' 'Critical bolting applications'
 
constitute reactor coolant pressure boundary components where closure bolting failure
 
could result in loss of reactor coolant and jeopardize safe operation of the plant. These 3-147 locations include bolted joints on the recirculation pumps and reactor coolant pressure boundary valves. Therefore, wear of reactor coolant pressure boundary bolted joints
 
requires aging management for the period of extended operation.
The staff concurred with the applicant's identification of loss of bolting function due to wear, in carbon and low-alloy steel and stainless steel bolting associated with GALL Report Items
 
IV.C1.3-e and IV.C1.2-d.
In LRA Table 3.1.2.4, for those components that fall under GALL Report Item IV.C1.2-d, the applicant indicated that the material listed in the GALL Report is different from the material used
 
at BFN (LRA Table 3.1.2.4, Footnote F). The applicant stated that the bolting used for
 
recirculation pump closure bolting is ASTM A540 Grade B23. Although the GALL Report lists
 
HSLA steel SA-193 Grade B7 for the applicable component, the staff concludes that
 
degradation due to wear of ASTM A540 Grade B23 bolting will be adequately managed by the
 
applicant's Bolting Integrity Program and is, therefore, acceptable.
In LRA Table 3.1.2.4, for those components that fall under GALL Report Item IV.C1.3-e, RCPB valve closure bolting, the applicant stated that the bolting is consistent with the GALL Report
 
item for component, material, environment, and aging effect in which the applicant's AMP takes
 
some exception to GALL Report Volume 2, (LRA Table 3.1.2.4, Footnote B). The staff found
 
acceptable the applicant's use of the Bolting Integrity Program, with exceptions, to manage
 
wear of GALL Report Item IV.C1.3-e components.
In LRA Table 3.1.2.4, the applicant identified loss of preload as an applicable aging effect due to stress relaxation. The bolting is exposed externally to the inside air environment and the
 
applicant credited its Bolting Integrity Program with management of this aging effect. The staff
 
concurs with the applicant that carbon and low-alloy steel and stainless steel bolting identified
 
above are susceptible to loss of preload due to st ress relaxation when exposed externally to the inside air environment. For those components that the applicant lists as being fabricated from a material not listed for corresponding GALL Report, Volume 2, Item IV.C1.2-e, the applicant
 
indicates that ASTM A 540 Grade B23 bolting is used in lieu of ASME SA 193 Grade B7, which
 
is listed in GALL Report Item IV.C1.2-e.
In RAI-3.1.2.4-1(A), dated December 1, 2004, the staff requested the applicant to provide additional information on the previous plant-specific experience of loss of bolting function due to
 
this aging effect. In addition, the applicant was asked to provide information on the scope and
 
the techniques of the past inspections, the results obtained, applied mitigative methods, repairs, frequency of its inspections and any other relevant information related to the identification of this
 
aging effect of the reactor recirculation systems and to provide information as to how the
 
plant-specific experience related to this aging effect impacts the attributes specified in the
 
Bolting Integrity Program.
In its response, by letter dated January 31, 2005 the applicant stated:
Stress relaxation was identified to be an aging effect that requires management for the period of extended operation for the reactor water recirculation pump closure bolting in
 
LRA Table 3.1.2.4, line item 2. The reactor water recirculation pump closure bolting is inspected in accordance with the requirements of ASME Section XI, Table IWB-2500-1, 3-148 Category B-G-1. Results of these inspections are provided below. [Table of Results is listed in RAI response]
Based on this review, no repairs have been performed on the reactor recirculation pump closure bolting. As discussed in LRA Section B.2.1.16, EPRI NP-5769, and the additional
 
recommendations of NUREG-1339 to prevent or mitigate degradation and failure of SR bolting
 
have been implemented. The plant-specific experienc e related to reactor recirculation pump closure bolting has no impact on the attributes specified in the Bolting Integrity Program.
The staff found the applicant's response to RAI 3.1.2.4-1(A) acceptable and concluded that the applicant's use of the Bolting Integrity Program will adequately manage loss of preload due to
 
stress relaxation in recirculation pump closure bolting, GALL Report Item IV.C1.2-e. Therefore, the staff's concern described in RAI 3.1.2.4-1(A) is resolved.
In LRA Table 3.1.2.4, the applicant lists RCPB valve closure bolting, (GALL Report Item IV.C1.3-f), as being susceptible to loss of bolting function due to stress relaxation. Revised LRA
 
Table 3.1.2.4 indicates that ASME SA 193 Grade B7 is used in some applications and the
 
Bolting Integrity Program is credited with managing this aging effect. The component, material, environment, and aging effect are consistent with the GALL Report. The AMP takes some
 
exceptions to the GALL Report. The staff found this acceptable.
The applicant also lists ASTM A 540 Grade B23 as being used for RCPB valve closure bolting (GALL Report Item IV.C1.3-f). Although the material is different from that listed in the GALL
 
Report, it is very similar and would be susceptible to the same aging effects as ASME SA 193
 
Grade B7. It would also be adequately managed by the same AMP (Bolting Integrity Program).
 
Therefore, the staff finds the applicant's use of the Bolting Integrity Program as an acceptable
 
method to manage loss of preload as a result of stress relaxation during the period of extended
 
operation.
In LRA Table 3.1.2.4, the applicant identified loss of bolting function (cumulative fatigue damage) due to fatigue as an applicable aging effects for carbon and low-alloy steel bolting
 
used on the recirculation pump and RCPB valve closure bolting. The applicant indicated that
 
ASTM A 540 Grade B23 as well as ASME SA 193 Grade B-7 are used. ASME SA 193 Grade
 
B-7 is the material referenced in the GALL Report for these components. These two materials
 
are similar and would both be potentially susceptible to fatigue. Therefore, the staff concurred
 
with the applicant that the referenced components are subject to cumulative fatigue damage
 
when exposed to inside air (external) environments.
For the reactor recirculation pump closure bolting (GALL Report Item IV.C1.2-f), the applicant listed fatigue as an applicable aging effect and indicated that fatigue is evaluated as a TLAA
 
and referenced LRA Section 4.3. The applicant indicated that its TLAA is consistent with the
 
GALL Report. The staff found the applicant's use of the TLAA "Metal Fatigue" in LRA
 
Section 4.3, acceptable to manage loss of bolting function due to fatigue for the period of
 
extended operation.
The applicant lists ASTM A 540 Grade B23 and ASME SA 193 Grade B7 as bolts used in the RCPB as valve closure bolting (GALL Report Item IV.C1.3-g). The material listed in the GALL
 
Report for this item number is SA 193 Grade B7. GALL requires a TLAA, meeting the
 
requirements of 10 CFR 54.21(c), to be performed for the extended period of operation for 3-149 GALL Report Item IV.C1.3-g. ASTM A 540 Grade B23 is also potentially susceptible to fatigue and the staff considers the GALL Report requirements for ASME SA 193 Grade B7 to also be
 
applicable to ASTM A540 Grade B23 bolting with regard to fatigue. The applicant indicated that
 
it has performed a TLAA that meets the requirements of 10 CFR 54.21(c) for ASTM A 540
 
Grade B23 and ASME SA 193 Grade B7 bolting used for RCPB valve closure bolting identified
 
as GALL Report Item IV.C1.3-g. Therefore, the staff found the applicant's AMR for these items
 
acceptable.
In LRA Table 3.1.2.4, the applicant identified biofouling and loss of material due to MIC, and crevice and pitting corrosion as AERMs in copper-alloy heat exchanger components that are
 
exposed to raw water environments internally. The AMR for these components has categorized them as the following: neither the component nor the material and environment combination is
 
evaluated in the GALL Report (i.e., LRA Table 3.1.2.4, Footnote J). The applicant credits the
 
Open-Cycle Cooling Water System Program to manage aging effects caused by biofouling and applicable forms of corrosion. The Open-Cycle C ooling Water System Program is evaluated in LRA Section 3.0.3.1.
The applicant identified loss of material due to crevice and pitting corrosion in copper-alloy piping in a treated water (internal) environment, GALL Report Item VII.C2.1-a. The applicant
 
indicated in the LRA that the One-Time Inspection Program is the credited AMP. The applicant
 
indicated that the material used is not consistent with the GALL Report and that the aging
 
effects identified for this material/environment combination are consistent with industry
 
guidance.The staff concurred with the applicant's determination that copper-alloy heat exchanger components that are subjected to a raw water environment internally are susceptible to
 
biofouling and loss of material due to MIC, crevice and pitting corrosion. The staff also
 
concurred with the applicant's identification of crevice and pitting corrosion in copper-alloy
 
piping in a treated-water environment.
In RAI 3.1.2.4-3, dated November 4, 2004, the staff requested the applicant to provide information regarding the heat exchangers, their function, and the selection of the credited AMP (One-Time Inspection Program). In its response, by letter dated December 9, 2004, the
 
applicant stated that the heat exchangers identified in LRA Table 3.1.2.4, Reactor Recirculation
 
System, are the reactor recirculation pump motor generator raw water/lubrication oil heat
 
exchangers for Unit 1 and the reactor recirculation pump, variable frequency drive, raw water
 
heat exchangers for Units 2 and 3. The Unit 1 reactor recirculation pump motor generators will
 
be replaced by variable frequency drives prior to Unit 1 restart. The applicant also stated that
 
the raw water environment for the heat exchangers is supplied from the raw water cooling
 
system and the appropriate AMP is the Open-Cycle Cooling Water Program. The Open-Cycle Cooling Water System Program includes condi tion monitoring such as system and component testing, visual inspection, and NDE testing. Preventive actions such as biocide treatment and
 
filtering are used to prevent loss of material due to MIC, biofouling, flow blockage, and reduction
 
of heat transfer due to biological and particle fouling. The applicant's Open-Cycle Cooling Water
 
System Program is evaluated in SER Section 3.
0.3.1 and consistent with the GALL Report after enhancements. The AMP credited by the applicant provides reasonable assurance that the
 
aging effects caused by biofouling, MIC, and crevice and pitting corrosion will be adequately
 
managed. The staff's concern described in RAI 3.1.2.4-3 is resolved.
3-150 For copper piping in a treated-water environment (internal), which the applicant identified as being susceptible to loss of material due to crevice and pitting corrosion, the staff requested in
 
RAI 3.1.2.4-4, dated November 4, 2004, that the applicant provide more information regarding
 
the operating and inspection history of the components. In its response, by letter dated
 
December 9, 2004, the applicant stated that the copper-alloy piping is an integral part of the
 
reactor recirculation pump variable frequency drives, which are recent additions to Unit 2 in
 
2003 and Unit 3 in 2004. Reactor recirculation pump variable speed drives will be installed in
 
Unit 1 prior to start up. The vendor manual identifies the material as red brass. The applicant
 
stated that the appropriate AMP is the Chemistry Control Program and the One-Time Inspection
 
Program. Red brass could suffer loss of material in a treated-water environment if the chemistry is not controlled properly. Given that the applicant will perform a one-time inspection to ensure
 
that degradation has not occurred and control the chemistry of the treated water, the potential
 
degradation of this piping due to crevice and pitting corrosion will be adequately managed
 
during the extended period of operation.
The staff reviewed the applicant's AMR for evaluating biofouling and loss of material due to MIC, crevice and pitting corrosion in heat exchanger copper-alloy components listed in LRA
 
Table 3.1.2.4 that are exposed to a raw water (internal) environment. The staff also reviewed
 
the applicant's AMR for evaluating loss of material due to crevice and pitting corrosion in
 
copper-alloy piping (GALL Report Item VII.C2.1-a) in a treated-water environment. On the basis
 
of its review, the staff found that the applicant had demonstrated that the effects of aging for
 
these components will be adequately managed so that their intended functions will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
3.1.2.3.5  Components with No Aging Effects in Inside Air Environment Externally and Components with No Aging Effects in Treated Water Environment Internally In LRA Table 3.1.2.4, the applicant identified several components where the materials used are not susceptible to aging effects identified in the GALL Report. The AMRs for these components
 
have categorized them as the following: material is not in the GALL Report item for this
 
component (i.e., LRA Table 3.1.2.4, Footnote F) and aging effect in the GALL Report item for
 
this component, material/environment combination is not applicable (i.e., LRA Table 3.1.2.4, Footnote I). In evaluating the aging effect, the applicant stated that for GALL Report Items
 
V.E.2-b and VII.I.2-b, carbon and low-alloy steel bolting are identified as being susceptible to
 
crack initiation and growth due to cyclic loading and SCC. GALL specifies the use of a Bolting Integrity Program in accordance with GALL AMP XI.M18. Under plant-specific notes, LRA
 
Table 3.1.2.4, Footnote 3, the applicant indicated that high yield-strength, heat-treated bolting is
 
not used and SCC and cracking due to cyclic loading are not concerns for BFN license renewal.
The applicant provided additional information along with its revised LRA Table 3.1.2.4 by letter dated March 16, 2005. The applicant stated the following:
The aging management review determined that this bolting is not susceptible to SCC as the yield strength of the ASME SA 193 Grade B7 bolting is less than 150 ksi. Crack
 
initiation and growth due to cyclic loading is not considered a license renewal concern
 
due to high cycle fatigue since it would be discovered during the current license period
 
and corrected. In addition, cyclic primary loads are evaluated against conservative stress
 
limits and are not a contributor to fatigue due to the few number of stress cycles 3-151 postulated (e.g., earthquake and fluid transient loads). The absence of crack growth due to cyclic loading and stress corrosion cracking identified in current line items 6 and 8 is
 
now shown in line items 10 and 12.
Typically, ASME SA193 Grade B7 bolting less than 150 ksi yield strength is not susceptible to SCC and would not require an AMP to manage cracking due to stress corrosion. With regard to
 
cracking due to cyclic loading, the staff concurred with the applicant that cracking due to cyclic
 
loading would not be applicable. The staff found the applicant's conclusion, that no AMP is
 
required for these item numbers, acceptable.
The applicant indicated, by letter dated March 16, 2005, that stainless steel non-RCPB bolting in the reactor recirculation system boundary was evaluated for aging effects such as corrosion, cracking due to cyclic loading, SCC, wear, stress relaxation, and fatigue. These
 
bolting/material/environment combinations are not addressed in the GALL Report. The applicant
 
stated that the bolting in question has a yield strength less than 150 ksi. The applicant identified
 
fatigue as being the only applicable aging effect for these bolts in an inside air (external)
 
environment. The applicant further stated that fatigue is addressed as a TLAA in LRA
 
Section 4.3. Based on a review of the applicant's March 16, 2005 letter, and considering the
 
environment, material and application, the staff concurred with the applicant's conclusion and
 
found its evaluation of the aforementioned bolts, in an inside air (external) environment, acceptable.
In GALL Report Volume 2, Items V-E-2-b and VII.I.2-b list carbon or low-alloy steel bolting as the applicable material and indicate that crack initiation and growth due to cyclic loading and
 
SCC are aging effects that require management during the extended period of operation.
 
Revised LRA Table 3.1.2.4 lists ASME SA 193 Grade B7, which is an HSLA material for these GALL Report item numbers. The AMR categorizes t hese line items as aging effects in the GALL Report item for this component/material/environm ent combination that are not applicable, and high yield-strength, heat-treated bolting, greater than150 ksi, is not used in non-RCPB bolting
 
applications at BFN (as evidenced in LRA Table 3.1.2.4, Footnote I,3). The staff did not
 
consider ASME SA 193 Grade B7 bolting less than 150 KSI as being susceptible to SCC in an
 
inside air (external) environment as described in the applicant's LRA. Therefore, the staff
 
concurs with the applicant's conclusion that no AMP is required for these components due to
 
cracking as a result of cyclic or SCC in an inside air (external) environment.
 
GALL Report Items VII.I.1-b and V.E.1-b are listed as being carbon or low-alloy components
 
that are susceptible to loss of material due to general corrosion in an inside air (external)
 
environment. LRA Table 3.1.2.4 lists copper alloy as the material used and does not list any
 
aging effects for material/environment as being applicable. The AMR categorizes this line item
 
as "material is not in the GALL Report item for this component" (LRA Table 3.1.2.4, Footnote F).
 
The staff does not consider copper-alloy components to be susceptible to any aging effects in
 
an inside air (external) environment. Therefore, the staff concurred with the applicant's
 
conclusion that no AMP is required for these components.
In RAI 3.1.2.4-5, dated November 4, 2004, the staff stated that the GALL Report Item V.C.1-b is listed as stainless steel valves; the material that is the same as used at BFN. The aging effects
 
listed in the GALL Report as requiring management are loss of material due to pitting, crevice
 
corrosion, MIC, and biofouling. The components are in a treated water (internal) environment, which is the same as listed in the GALL Report. Therefore, the staff requested that the applicant 3-152 discuss the age, operating history, and inspection history of the valves. The staff also requested that the applicant provide a detailed explanation of the attributes of the system design that make
 
degradation due to MIC and biofouling not applicable.
In its response, by letter dated December 9, 2004, the applicant stated that the water in this cooling water subsystem is demineralized water that has no history of microbiologically
 
influenced corrosion activity. The staff found this acceptable because stainless steel in a
 
demineralized water environment would not be considered susceptible to loss of material due to
 
pitting, crevice corrosion, MIC, and biofouling. Therefore, the staff's concern described in
 
RAI 3.1.2.4-5 is resolved.
In LRA Table 3.1.2.4, the applicant also identified several components in which the material used is not susceptible to aging effects identified in the GALL Report. The AMR for these
 
components categorized them as the following: "material is not in GALL Report item for this
 
component" (LRA Table 3.1.2.4, Footnote F) and the aging effect in the GALL Report item for
 
this component/material/environmental combination is not applicable (i.e., LRA Table 3.1.2.4, Footnote I).
GALL Report Items V.E.2-b and VII.I.2-b, carbon and low-alloy steel bolting, are identified as being susceptible to crack initiation and growth due to cyclic loading and SCC. The GALL
 
Report specifies the use of a Bolting Integrity Program in accordance with GALL Report Volume 2, Chapter XI.M18. Under plant-specific notes, LRA Table 3.1.2.4, Footnote 3, the applicant
 
indicated that high yield-strength, heat-treated bolting is not used at BFN and SCC and cracking
 
due to cyclic loading are not concerns for license renewal. The staff followed up and sought
 
clarifications on the LRA Table 3.1.2.4 information.
The applicant provided additional information along with its revised LRA Table 3.1.2.4 by letter dated March 16, 2005. The applicant stated the following:
The aging management review determined that this bolting is not susceptible to SCC as the yield strength of the ASME SA 193 Grade B7 bolting is less than 150 ksi. Crack
 
initiation and growth due to cyclic loading is not considered a license renewal concern
 
due to high cycle fatigue since it would be discovered during the current license period
 
and corrected. In addition, cyclic primary loads are evaluated against conservative stress
 
limits and are not a contributor to fatigue due to the few number of stress cycles
 
postulated (e.g., earthquake and fluid transient loads). The absence of crack growth due
 
to cyclic loading and stress corrosion cracking identified in current line items 6 and 8 is
 
now shown in line items 10 and 12.
Typically, ASME SA193 Grade B7 bolting, less than 150 ksi yield strength, is not susceptible to stress corrosion cracking and would not require an AMP to manage cracking due to stress
 
corrosion. With regard to cracking due to cyclic loading, the staff concurs with the applicant that
 
cracking due to cyclic loading would not be applicable. The staff finds the applicant's
 
conclusion, that no AMP is required for these item numbers, acceptable.
The applicant indicated, by letter dated March 16, 2005, that stainless steel non-RCPB bolting in the reactor recirculation system boundary was evaluated for aging effects such as corrosion, cracking due to cyclic loading and SCC, wear, stress relaxation, and fatigue. These
 
bolting/material/environment combinations are not addressed in the GALL Report. The applicant 3-153 stated that the bolting in question has a yield strength less than 150 ksi. The applicant identified fatigue as being the only applicable aging effect for these bolts in an inside air (external)
 
environment. The applicant further stated that fatigue is addressed as a TLAA in LRA
 
Section 4.3. Based on a review of the applicant's March 16, 2005 letter, and considering the
 
environment, material and application, the staff concurred with the applicant's conclusion and
 
finds its evaluation of the aforementioned bolts, in an inside air (external) environment, acceptable.
In GALL Report Volume 2, Items V-E-2-b and VII.I.2-b list carbon or low-alloy steel bolting as the applicable material and indicates that crack initiation and growth due to cyclic loading/SCC
 
are aging effects that require management during the extended period of operation. Revised
 
LRA Table 3.1.2.4 lists ASME SA 193 Grade B7, which is an HSLA material for these GALL Report item numbers. The AMR categorizes these line items as: "Aging effect in NUREG-1801
 
item for this component, material and environment combination is not applicable and high yield
 
strength heat-treated bolting, greater than150 ksi, is not used in non-RCPB bolting applications
 
at BFN" (LRA Table 3.1.2.4, Footnote I,3). The staff did not consider ASME SA 193 Grade B7
 
bolting less than 150 KSI as being susceptible to SCC in an inside air (external) environment as
 
described in the applicant's LRA. Therefore, the staff concurred with the applicant's conclusion
 
that no AMP is required for these components due to cracking as a result of cyclic or SCC in an
 
inside air (external) environment.
 
GALL Report, Items VII.I.1-b and V.E.1-b are listed as being carbon or low-alloy components
 
that are susceptible to loss of material due to general corrosion in an inside air (external)
 
environment. LRA Table 3.1.2.4 lists copper alloy as the material used and does not list any
 
aging effects for the material/environment as being applicable. The AMR categorizes this line
 
item as "material is not in the GALL Report item for this component," (LRA Table 3.1.2.4, Footnote F). The staff does not consider copper-alloy components to be susceptible to any
 
aging effects in an inside air (external) environment. Therefore, the staff concurred with the
 
applicant's conclusion that no AMP is required for these components.
3.1.2.3.6  SCC in RV Flange Leak Detection Line and Jet Pump Sensing Line
 
SRP-LRA Section 3.1.3.2.4.2 states that the crack initiation and growth due to thermal and mechanical loading or SCC, including IGSCC, could occur in the BWR RV flange detection line
 
and jet pump sensing line. The GALL Report recommends that a plant-specific AMP be
 
evaluated to mitigate or detect crack initiation and growth due to SCC of the vessel flange
 
detection line and jet pump sensing line.
 
In LRA Section 3.1.2.2.4, the applicant addressed vessel flange leak detection lines that are
 
subjected to SCC. The applicant proposed to use the One-Time Inspection Program for
 
managing this aging effect.
In RAI 3.1.1-1, dated December 1, 2004, the staff requested that the applicant provide information on the plant-specific experience related to cracking due to SCC in the vessel flange
 
leak detection lines at the BFN units, and its method of implementation of the One-Time
 
Inspection Program. The staff also requested the applicant to provide justification for using
 
one-time inspection in detecting the cracking due to SCC in a timely manner.
3-154 In its response, by letter dated January 31, 2005, the applicant indicated that, in addition to theOne-Time Inspection program, the ASME Code Section XI Subsections IWB, IWC, and IWD
 
Inservice Inspection Program will be implemented for the RV flange leak detection lines. The
 
applicant stated that it will revise the first paragraph in LRA Section 3.1.2.2.4 to include the ISI
 
program as an additional AMP for the RV flange leak detection lines. The applicant stated that
 
the AMR shown in LRA Table 3.1.2.1 will be revised to include the aging effects (cracking
 
growth from cyclic loading, loss of material due to crevice, pitting, and general corrosion), and
 
their associated AMPs (One-Time Inspection Program and ISI Program) for the carbon steel
 
and low-alloy steel RV heads, flanges, and shells. The staff found this response acceptable.
 
The proposed AMPs will provide adequate measures in managing the aging effects of the RV
 
flange leak detection lines. Therefore, the staff's concern described in RAI 3.1.1-1 is resolved.
In LRA Section 3.1.2.2.4, the applicant addressed jet pump sensing lines that are subject to SCC. The applicant proposed to use the Chemistry Control Program and One-Time Inspection
 
Program for managing this aging effect.
In RAI 3.1.1-2, dated December 1, 2004, the staff requested that the applicant provide information on the plant-specific experience related to cracking due to SCC in jet pump sensing
 
lines, and its method of implementing the One-Time Inspection Program. The staff also
 
requested that the applicant provide justification for using the One-Time Inspection Program to
 
detect cracking due to SCC in a timely manner.
In its response to RAI 3.1.1-2, by letter dated January 31, 2005, the applicant stated that the jet pump sensing lines have not previously exper ienced cracking due to SCC, IGSCC or cyclic loading. The jet pump sensing lines inside the RV are not within the scope of the license
 
renewal process. According to Section 2.3.12.7 of the BWRVIP-41, "BWR Jet Pump Assembly
 
Inspection and Flaw Evaluation Guidelines," inspection of the jet pump sensing lines is
 
continuously occurring during the plant operation. Therefore, if this line fails, plant technical
 
specifications require either a plant shutdown or a safety assessment to justify continued
 
operation. Therefore, the failure of the sensing lines inside the RV has no adverse safety
 
consequences and does not need to be included within the scope of license renewal. However, the applicant agreed to revise the AMR by adding the AMPs (shown below) for the jet pump
 
sensing line penetrations and external lines that are listed in LRA Tables 3.1.2.1 and 3.1.2.4.
 
The applicant included the BWR Reactor Penetration Program for managing the aging effect
 
related to cracking due to SCC in the jet pump sensing lines penetrations at BFN. The applicant stated that this AMP is consistent with GALL AMP XI.M8, "BWR Penetrations," with no
 
exceptions. BWR Reactor Penetration Program includes the staff's approved versions of
 
BWRVIP-27, "BWR Standby Liquid Control System/Core Plate delta P Inspection and Flaw
 
Evaluation Guidelines," and BWRVIP-49, "Instrumentation Penetration Inspection and Flaw
 
Evaluation Guidelines." SER Section 3.0.3.2.6 presents the staff's detailed review of this AMP.
The staff finds the applicant's response to RAI 3.1.1-2 acceptable, and the staff's concern described in this RAI is resolved.
The applicant stated that the Chemistry Control Program will be used at BFN to manage SCC in the jet pump sensing lines. The Chemistry Control Program is based on EPRI Report
 
TR-103515-R2, (the 2000 revision of "BWR Water Chemistry Guidelines"), which was approved
 
by the staff in February 2000. The staff found the EPRI TR-103515-R2 acceptable because the program is based on updated industry experience and plant-specific and industry-wide 3-155 operating experience that confirms the effectiveness of the RCS chemistry program. The staff found that implementation of the Chemistry Cont rol Program would be consistent with the GALLAMP XI.M2; therefore, it is acceptable. In addition, the proposed inspection AMPs would ensure
 
the identification of cracking due to SCC, IGSCC, and cyclic loading in a timely manner so that
 
the intended function of the jet pump sensing lines is not sacrificed. Therefore, the staff
 
concluded that by the implementation of the additional AMPs, the aforementioned aging effects
 
of the jet pump sensing lines would be managed effectively during the extended period of
 
operation.
3.1.2.3.7  Stainless Steel Reactor Vessel Attachment Welds
 
The AMPs recommended by the GALL Report for managing the cracking due to SCC, IGSCC,and cyclic loading for the RV attachment welds are XI.M4, "BWR Vessel Inner Diameter (ID)
Attachment Welds," and XI.M2, "Water Chemistry," which references EPRI Report TR-103515.
In LRA Table 3.1.2.1, the applicant identified IGSCC as an aging effect for the stainless steel RV attachment welds. The applicant stated the Chemistry Control Program will be used at BFN
 
to manage this aging effect. The Chemistry Control Program is based on EPRI Report
 
TR-103515-R2, (the 2000 revision of "BWR Water Chemistry Guidelines"), which was approved
 
by the staff in February 2000.
The staff found EPRI TR-103515-R2 acceptable because the program is based on updated industry experience and plant-specific and industry-wide
 
operating experience that confirms the effectiveness of the RCS chemistry program. The applicant indicated that the vessel attachment welds program is discussed in LRA
 
Section B.2.1.7, "BWR Vessel ID Attachment Welds." LRA Section B.2.1.7 references LRA Section B.2.1.4, "ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection
 
Program." The applicant's ISI Program is an established AMP. This program has appropriate requirements for inspecting the vessel ID attachment welds. "BWR Vessel ID Attachment
 
Welds" also invokes the inspection and evaluation recommendations of BWRVIP-48, "Vessel ID
 
Attachment Weld Inspection and Evaluation Guidelines." SER Section 3.0.3.2.3 presents the
 
staff's detailed review of this AMP.
In RAI 3.1.2.1-1, dated December 1, 2004, the staff requested that the applicant provide the method of implementation of the type and frequency of inspections that are specified in
 
BWRVIP-48, "Vessel ID Attachment Welds Inspection and Flaw Evaluation Guidelines." These
 
requirements apply to jet pump raiser brace attachments, core spray piping bracket
 
attachments, steam dryer support and hold-down brackets, feedwater spargers, guide rods, and
 
surveillance sample holders. According to BWRVIP-48 Section 2.2.3, furnace-sensitized
 
stainless steel vessel ID attachment welds are highly susceptible to IGSCC. The staff requested
 
the applicant to identify whether there are any furnace-sensitized stainless steel attachment
 
welds at BFN, and to provide information regarding an augmented inspection program for any
 
existing furnace-sensitized stainless steel attachment welds.
In its response to RAI 3.1.2.1-1, by letter dated January 31, 2005, the applicant stated that all the ID RV attachment welds had been inspected in accordance with BWRVIP-48 and ASME Code Section XI ISI requirements for type and frequency. The applicant indicated that all the ID
 
attachment welds are furnace-sensitized; therefore, an augmented inspection program in
 
accordance with the requirements of BWRVIP-48 will be implemented for all these welds. The
 
staff found that this type of inspection would ensure that the aforementioned aging effects are properly managed for the extended period of operation. The staff found that the implementation 3-156of the ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program, Chemistry Control Program, and BWR ID Attachm ent Welds Program would be consistent withthe GALL AMPs XI.M2 and XI.M4, and is acceptable. Therefore, the staff's concern described in
 
RAI 3.1.2.1-1 is resolved. SER Sections 3.0.3.2.2 and 3.0.3.1.3 respectively, present the staff's
 
detailed review of these AMPs. SER Sections 3.0.3.2.2 and 3.0.3.1.3, respectively, present the
 
staff's detailed reviews of these AMPs.
3.1.2.3.8  Reactor Vessel Nozzles and Safe Ends
 
The AMPs recommended by the GALL Report for managing the cracking due to SCC, IGSCCand cyclic loading for the RV nozzles and safe ends are XI.M7, "BWR Stress Corrosion Cracking," and XI.M2, "Water Chemistry," which references EPRI Report TR-103515.
In Table 3.1.2.1 of the LRA, the applicant indicated that stainless steel materials in the RV nozzle and safe end components, when exposed to a treated-water environment, experience cracking due to SCC. The applicant credited the BWR Stress Corrosion Cracking Program, ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program, which is an
 
established AMP. In addition, the applicant indicated that AMP B.2.1.5, "Chemistry Control
 
Program," is based on EPRI Report TR-103515-R2, (the 2000 revision of "BWR Water
 
Chemistry Guidelines"), which was approved by the staff in February 2000.
In RAI 3.1.2.1-4(C), the staff requested that the applicant identify whether the dissimilar metal welds of reactor vessel nozzles and safe end components have previously experienced cracking due to SCC, IGSCC, or cyclic loading, and the extent of cracking. In its response to
 
RAI 3.1.2.1-4(C), by letter dated January 31, 2005, the applicant stated that, for the dissimilar
 
metal welds in nozzles and safe end components and piping, the requirements of ASME Code Section XI, Subsections IWB, IWC and IWD ISI Program inspections and frequencies in accordance with ASME Code Section XI, Table IWB-2500-1, examination category B-F would
 
be met. The applicant's BWR IGSCC program inspections and frequencies are in accordance
 
with the normal water chemistry guidelines contained in BWRVIP-75, "BWR Vessel and
 
Internals Project (BWRVIP), Technical Basis for Revisions to Generic Letter 88-01 Inspection
 
Schedule." The applicant implemented alternativ e examination requirements for IGSCC Category A (as defined in BWRVIP-75) dissimilar metal welds under a risk-informed ISI program (previously approved by the staff) for Units 2 and 3. The applicant stated that it performed liquid
 
penetrant testing (PT) and UT of the dissimilar welds in recirculation inlet and outlet
 
nozzle-to-safe ends, the core spray nozzle-to-safe end, pipe-to-safe ends, and the CRD
 
nozzle-to-cap welds for Units 2 and 3; and the examination results were acceptable. The
 
applicant stated that for Unit 1 it performed PT and UT examinations on CRD nozzle-to-cap
 
welds, and the examination results were acceptable. The applicant stated that for Unit 1 the
 
RCS water chemistry would be improved in accordance with the BWR SCC Program, and the
 
CRD nozzle-to-safe end welds would be replaced prior to the period of extended operation.
The applicant also stated that improvements in RCS water chemistry provide mitigative measures to preclude IGSCC in the dissimilar welds in nozzle-to-safe end, pipe-to-safe end, and nozzle-to-cap components. The staff accepts the proposed program for stainless steel safe
 
ends because it conforms to the recommendations in the BWRVIP-75; however, if the safe ends
 
contain nickel-alloy weld metals that are susceptible to SCC, BWRVIP-75 would require more
 
frequent examinations than those specified for BWRVIP-75 Category A welds. In order for the
 
staff to determine whether the applicant had adequately implemented BWRVIP-75, the staff 3-157 requested that the applicant identify (1) the weld metal that was used for the butter, nozzle-to-safe end welds, pipe-to-safe end welds, and nozzle-to-cap welds; (2) the grade of
 
stainless steel that was used as a safe end; and (3) the examination requirements for butter, nozzle-to-safe end welds, pipe-to-safe end welds, and nozzle-to-cap welds that are more
 
susceptible to SCC than the BWRVIP-75 Category A welds.
The applicant, in its response dated May 25, 2005, indicated that stainless steel weld metal was used for the butter on the nozzle-to-safe end welds and that it would implement the inspection
 
guidelines that are specified in the BWRVIP-75 report for the subject welds. Since the stainless
 
steel weld metal is less susceptible to IGSCC than nickel-alloy weld metal, the staff concludes
 
that inspection requirements as specified in the BWRVIP-75 guidelines will adequately identify
 
aging degradation in a timely manner. The applicant further stated that it used nuclear grade (low carbon) stainless steel for the safe end material in recirculation and core spray systems
 
with the exception of non-nuclear grade (i.e., standard carbon content) stainless steel safe ends
 
in the recirculation outlet welds in Units 2 and 3. The applicant proposed to implement the
 
BWRVIP-75 inspection guidelines, which are acceptable to the staff because they provide
 
adequate assurance in identifying cracking due to IGSCC in a timely manner for nozzle-to-safe
 
end welds. Since the stainless steel weld metal and nuclear grade stainless steel safe end
 
materials (with exception noted above) are less susceptible to IGSCC, the staff concluded that
 
the applicant's proposed inspection guidelines will adequately manage aging effects in the
 
recirculation and core spray systems. With respect to the non-nuclear grade recirculation outlet
 
nozzles and their welds in Units 2 and 3, the applicant stated that it will use a mechanical stress
 
improvement (MSIP) method to mitigate IGSCC and will use Category C inspection guidelines
 
to monitor the aging effects in these welds. The staff found the response acceptable because
 
the applicant's proposed mitigation and inspection methods for the recirculation outlet nozzle
 
welds will comply with the staff-approved BWRVIP-75 inspection criteria and will enable the
 
applicant to identify IGSCC in a timely manner. Therefore, the staff's concern described in
 
RAI 3.1.2.1-4(C) is resolved.
3.1.2.3.9  Feedwater Nozzle GALL AMP XI.M5, "BWR Feedwater Nozzle," recommends that inspection requirements specified in GE-NE-523-A71-0594, "Alternate BWR Feedwater Nozzle Inspection
 
Requirements," be implemented for the feedwater nozzles for managing cracking due to cyclic loading for the feedwater nozzles.
The applicant included the BWR Feedwater Nozzle Program for managing the aging effect related to cracking due to cyclic loading in the feedwater nozzles at BFN. The applicant stated that the program is consistent with GALL AMP XI.M5, with no exceptions. The applicant also invoked the ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection
 
Program, which is an established AMP. This program has appropriate requirements for
 
inspecting the feedwater nozzle components. The applicant also stated that the program enhances the ISI specified in ASME Code Section XI with the recommendations of
 
GE-NE-523-A71-0594. The applicant stated that it implemented the recommendations of
 
NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking,"
 
to mitigate feedwater nozzle cracking. The applicant also stated that the feedwater nozzles had
 
been modified to mitigate cracking by removing the stainless steel cladding and machining the
 
safe end, nozzle bore, and inner bend radius to accept improved double-piston-ring
 
interference-fit spargers with a forged tee design and orificed elbow discharges. The applicant 3-158 indicated in the LRA that the reactor water cleanup system return lines were routed to both feedwater headers (except Unit 2, which is only routed to one feedwater header). The applicant
 
stated that changes to plant operating procedures, such as improved feedwater control, to
 
decrease the magnitude and frequency of temperature fluctuations had been implemented at
 
Units 2 and 3. The applicant also indicated t hat similar improvement s will be implemented at Unit 1 prior to the period of extended operation. SER Section 3.0.3.2.4 presents the staff's
 
detailed review of the BWR Feedwater Nozzle Program.
In RAI 3.1.2.1-4(B), dated December 1, 2004, the staff requested that the applicant provide information on the scope and the techniques of past inspections, the results obtained, applied
 
mitigative methods, repairs, frequency of the inspections, and any other relevant information
 
related to the identification of the aging effect in the feedwater nozzles at BFN. The staff further
 
requested that the applicant provide information as to how the plant-specific experience related
 
to this aging effect impacts the attributes specified in the BWR Feedwater Nozzle Program.
In its response, by letter dated January 31, 2005, the applicant stated that it complied with the inspection requirements specified in the BWR Feedwater Nozzle Program. The applicant stated
 
that it had performed UT of the feedwater nozzles and the results were acceptable, and no
 
repairs were performed in this system. Therefore, the applicant concluded that the plant-specific
 
experience related to feedwater nozzles has no impact on the attributes specified in the BWR
 
Feedwater Nozzle Program. The staff reviewed the applicant's response and found it
 
acceptable. The applicant demonstrated that the actions taken thus far have mitigated cracking
 
in feedwater nozzles. Therefore, the staff's concern described in RAI 3.1.2.1-4(B) is resolved.
In RAI B.2.1.8-1, the staff stated that the BWR Feedwater Nozzle Program references GE report GE-NE-523-A71-0594, which is not the staff-approved version of the report. The staff requested
 
that the applicant replace references to GE-NE-523-A71-0594 in LRA Sections A.1.8 and
 
B.2.1.8 with GE-NE-523-A71-0594-A, Revision 1 which is approved by the staff. In its response
 
to RAI B.2.1.8-1, by letter dated January 31, 2005, the applicant stated that it will revise the LRA
 
to indicate correct GE report. In its response, by letter May 25, 2005, the applicant submitted a
 
revised version of LRA Section A.1.8, and the BWR Feedwater Nozzle Program, which includes
 
GE-NE-523-A71-0594-A, Revision 1. The staff found that the implementation of ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program and the BWR Feedwater Nozzle Program would be consistent with GALL AMP XI.M5 and, therefore, is acceptable. The staff's concern described in
 
RAI B.2.1.8-1 is resolved.
3.1.2.3.10  Control Rod Drive (CRD) Return Line Nozzle GALL AMP XI.M6, "BWR Control Rod Drive Return Line Nozzle," recommends that enhanced inspection requirements specified in NUREG-0619, "BWR Feedwater Nozzle and Control Rod
 
Drive Return Line Nozzle Cracking," should be implemented for the CRD return line nozzles for
 
managing the cracking due to cyclic loading for the CRD return line nozzle.
In LRA Table 3.1.2.1, the applicant referenced BWR CRD Return Line Nozzle Program, for managing the aging effect in the CRD return line. The applicant stated that the program is consistent with GALL AMP XI.M6, with no exceptions. The applicant indicated that inspections that are specified in NUREG-0619, and ASME Code Section XI Subsections IWB, IWC, and 3-159 IWD Inservice Inspection Program, which is an established AMP. This program has appropriate requirements for inspecting the CRD return line nozzle components.
In RAI B.2.1.9-1, dated December 1, 2004, the staff requested the applicant to provide information on the augmented inspection requirements that are specified in the NUREG-0619.
 
The CRD return line nozzle has been capped; therefore, augmented inspection of the nozzle is
 
not needed per NUREG-0619. The guidance in NUREG-0619 provide actions to be taken to
 
address cracking in these nozzles; however, the aging effects for the cap and applicable weld
 
are not covered in NUREG-0619. Therefore, the staff requested that the applicant address the
 
following issues concerning the cap and weld that provide a pressure boundary function:
In RAI B.2.1.9-1(1) the applicant was requested to describe the configuration, location and material of construction of the capped nozzle, including the existing base material for the
 
nozzle, piping (if piping remnants exist) and cap material, and any welds. In its response by
 
letter dated January 31, 2005, the applicant stated that the configuration consists of a stainless
 
steel cap welded to the original carbon steel nozzle with stainless steel weld material. The safe
 
end and corresponding piping had been removed from the nozzle. In RAI B.2.1.9-1(2) the applicant was requested to describe the application of the BWRVIP-75
 
inspection guidelines for this weld and cap. In its response to RAI B.2.1.9-1(2), by letter dated
 
January 31, 2005, the applicant stated that the requirements of BWRVIP-75 are implemented by
 
the BWR Stress Corrosion Cracking Program. The CRD return line nozzle welds are currently
 
categorized (BWRVIP-75) as Category D for Unit 2 and Category C for Unit 3. The CRD return
 
line nozzle welds are examined by the UT technique at the frequency specified by BWRVIP-75, Table 3-1 for normal water chemistry conditions. The applicant stated that it will implement the
 
BWR Stress Corrosion Cracking Program for Unit 1 prior to the period of extended operation. The staff reviewed the applicant's response and found it acceptable provided the applicant
 
includes information in the LRA regarding the category (per BWRVIP-75) of the subject weld in
 
Unit 1.
 
In RAI B.2.1.9-1(3) the applicant was requested to discuss the applicability of the event at
 
Pilgrim (leaking weld at a capped nozzle, September 30, 2003) to BFN. The staff issued
 
IN 2004-08, dated April 22, 2004, which states that the cracking occurred in an alloy 82/182
 
weld that had previously been repaired at the Pilgrim unit. According to IN 2004-08, the Pilgrim
 
CRD return line nozzle is made of SA-508, Class 2 low-alloy steel, while the CRD return line
 
cap is made of Alloy 600. The subject weld is fabricated with Alloy 82/182 material, and the
 
nozzle side of the weld is buttered with Alloy 182 material. In addition, Pilgrim had initial weld
 
deficiencies (lack of fusion) that required weld repair. The staff also requested that the applicant
 
provide any plant experience with leakage at the capped nozzle, the past inspection techniques
 
used, results obtained, and mitigative strategies imposed. The staff requested that the applicant
 
provide information as to how the plant-specific experience related to this aging effect impacts
 
the attributes specified in the BWR CRD Return Line Nozzle Program.
In its response, by letter dated January 31, 2005, the applicant stated that the event at Pilgrim was determined not to be applicable. The materials of construction of the nozzle-to-cap weld at
 
BFN is stainless steel. The welds were completed without recordable indications. Plant
 
experience for Units 2 and 3 indicates that there has been no leakage at the capped CRD return
 
line nozzles. Ultrasonic exams have been performed with no reportable indications. The Unit 3 3-160 capped CRD return line nozzle weld had MSIP performed to mitigate IGSCC, which changed the frequency of inspection. The examination information related to this item is described in
 
RAI B.2.1.9-1(2). The plant-specific experience related to the CRD return line nozzle has no
 
impact on the attributes specified in the BWR CRD Return Line Nozzle Program.
The staff reviewed the applicant's responses and found them acceptable, in part, because the improved RCS water chemistry and MSIP (for Unit 3) should provide adequate mitigation to
 
preclude IGSCC. However, the staff found that, unlike weld metal Alloy 182, austenitic stainless
 
steel weld metal (with a minimum delta ferrite) is less susceptible to IGSCC. In addition, low
 
carbon austenitic stainless steel material (L grade) is less susceptible to IGSCC than non-L
 
grade austenitic stainless steel.
In order for the staff to determine whether the applicant had adequately implemented BWRVIP-75 for the Category A CRD return line nozzle welds, the staff requested that the
 
applicant identify (1) the delta ferrite in the weld metal, (2) the grade of stainless steel that was
 
used for the CRD return line cap, (3) the examination requirements for CRD return line welds
 
that meet BWRVIP-75, and (4) plans to implement MSIP in Units 1 and 2.
In its response dated May 25, 2005, the applicant indicated that stainless steel weld metal with a minimum of eight percent delta ferrite was used for the CRD return line nozzle-to-cap welds
 
and that it will implement inspection guidelines as specified in the BWRVIP-75 report for the
 
subject welds. The applicant proposed to implement BWRVIP-75 inspection guidelines, which
 
are acceptable to the staff because they provide adequate assurance in identifying cracking due
 
to IGSCC in a timely manner for nozzle-to-safe end welds. Since the stainless steel weld metal
 
with eight percent delta ferrite is less susceptible to IGSCC than nickel-alloy weld metal, the
 
staff concluded that inspection requirements as specified in the BWRVIP-75 guidelines will
 
adequately identify aging degradation in a timely manner.
The applicant further stated that it used low carbon grade stainless steel for the CRD return line cap materials. Since the stainless weld metal and low carbon grade stainless steel CRD return
 
line cap materials are less susceptible to IGSCC, the staff concluded that the applicant's
 
proposed inspection guidelines will adequately manage the aging effect in the CRD return line
 
nozzle-to-cap welds. Regarding the application of MSIP as a mitigative technique to improve
 
resistance to IGSCC, the applicant stated that it will use the following plan to implement MSIP
 
for CRD return line nozzle-to-cap welds: (1) MSIP and BWRVIP-75 inspection guidelines will be
 
implemented for Unit 1 welds prior to restart; (2) no MSIP will be used for Unit 2 welds;
 
however, BWRVIP-75, Category D inspection guidelines will be implemented for these welds;
 
and, (3) MSIP was used in Unit 3 welds and the BWRVIP-75, Category C inspection guidelines
 
will be use for these welds. The staff found the response acceptable because the applicant's
 
proposed mitigation and inspection methods for the CRD return line nozzle-to-cap welds will
 
comply with the staff approved BWRVIP-75 inspection criteria, and will enable the applicant to
 
identify IGSCC cracking in a timely manner. Therefore, the staff's concern described in
 
RAI B.2.1.9-1 is resolved.
The staff found that the implementation of the BWR CRD Return Line Nozzle Program andASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program for the CRD return lines would be consistent with the GALL AMP XI.M6, and is, therefore, acceptable.
 
SER Section 3.0.3.1.5 presents the staff's detailed review of this AMP.
3-161 3.1.2.3.11  Reactor Vessel Penetrations AMPs recommended by the GALL Report for managing cracking due to IGSCC for the RVpenetrations are XI.M8, "BWR Penetration," and XI.M2, "Water Chemistry." The GALL AMPs for
 
the RV penetrations include implementation of guidelines specified in BWRVIP-49, "Instrumentation Penetration Inspection and Flaw Evaluation Guidelines," and reactor coolant
 
water chemistry in accordance with the guidelines of BWRVIP-29, "BWR Water Chemistry Guidelines," (EPRI TR-103515). In addition to these requirements, the GALL program XI.M8, "BWR Penetration," recommends that inspection and flaw evaluation guidelines specified in
 
BWRVIP-27, "BWR Standby Liquid Control System/Core Plate delta P Inspection and Flaw
 
Evaluation Guidelines," should be implemented for the RV penetrations.
In LRA Table 3.1.2.1, the applicant indicated that nickel-alloy and stainless steel materials in the RV penetration components, when exposed to a treated-water environment, experience cracking due to SCC. The applicant included the BWR Reactor Penetration Program for
 
managing the aging effect related to cracking due to SCC in the RV penetrations. The applicant stated that this AMP is consistent with GALL AMP XI.M8 with no exceptions. The BWR Reactor
 
Penetration Program recommends the implementation of the staff's approved versions of BWRVIP-27, BWRVIP-49, and ASME Section XI Subsections IWB, IWC, and IWD Inservice
 
Inspection Program, which is an established AM P. This program has appropriate requirements for inspecting the BWR RV penetrations (i.e., category B-E for pressure-retaining partial
 
penetration welds; category B-D for full penetration nozzle-to-vessel welds; category B-F for
 
pressure retaining dissimilar metal nozzle-to-safe end welds; and category B-J for similar metal
 
nozzle-to-safe end welds). The extent and schedule of inspection prescribed by the ASME Code Section XI ISI Program is designed to maintain structural integrity and ensure that aging effects
 
will be discovered and repaired before the loss of intended function of the component. These
 
inspections can reveal crack initiation and growth and leakage of coolant due to SCC. In
 
addition, the applicant indicated that the Chemistry Control Program, which is based on EPRI
 
Report TR-103515-R2, (the 2000 revision of "BWR Water Chemistry Guidelines"), will be
 
applied. The staff found the EPRI TR-103515-R2 acceptable because the program is based on
 
updated industry experience, and plant-specific and industry-wide operating experience confirm
 
the effectiveness of the RCS chemistry program.
In RAI 3.1.2.1-5(B), dated December 1, 2005, the staff requested that the applicant provide any
 
previous plant-specific experience regarding t he cracking due to SCC and IGSCC in dissimilar metal welds of RV penetrations, and the method and frequency of inspection for managing this
 
aging effect. In its response to RAI 3.1.2.1-5(B), by letter dated January 31, 2005, the applicant stated that the following penetrations are inspected during the ASME Code Section XI, IWB-2500, Code Category B-P system leakage test during each refuel outage: (1) CRD stub
 
tubes; (2) instrumentation nozzle/nozzle safe ends; (3) standby liquid control nozzles; (4) jet
 
pump instrumentation nozzles; (5) drain line nozzles; and (6) in-core monitor housing
 
penetrations.
The applicant also stated that no cracking of the dissimilar metal penetration welds have been identified thus far at BFN. In addition, the applicant stated that the improvements in the RCS
 
Chemistry Control Program would mitigate the IGSCC of the RV penetration welds. The
 
applicant stated that the plant-specific experience related to the RV penetrations has no impact
 
on the attributes of the BWR Penetrations Program.
3-162 The staff reviewed the response to the RAI 3.1.2.1-5(B) and found it acceptable. Implementation of the improved water chemistry and ISI programs as specified in the BWR Penetrations
 
Program, would enable the applicant to manage the aging effect due to IGSCC effectively during the extended period of operation, and would be consistent with GALL AMPs XI.M8 and XI.M2. Therefore, the staff's concern in RAI 3.2.1.2-5(B) is resolved.
3.1.2.1.12  Reactor Head Closure Studs GALL AMP XI.M3, "Reactor Head Closure St uds," recommends that preventive actions specified in RG 1.65, "Materials and Inspections for RV Closure Studs," should be implemented
 
for managing the cracking due to SCC for the reactor head closure studs. SER Section 3.0.3.1.4
 
present the staff's detailed review of this AMP.
In LRA Table 3.1.2.1, the applicant indicates that the Reactor Head Closure Studs Program,which is consistent with GALL AMP XI.M3, will be implemented to monitor the aging effect due
 
to SCC of the reactor head closure studs.
The applicant stated that the following requirements will be implemented for the Reactor Head Closure Studs Program.
* ISI in conformance with the requirements of the ASME Code Section XI, Subsection IWB, Table IWB 2500-1.
* Mitigation of cracking is achieved by complying with the requirements of Regulatory Guide 1.65, "Materials and Inspections for RV Closure Studs." The applicant stated that
 
approved lubricants will be used to minimize the potential for cracking of the
 
non-metal-plated reactor head closure studs.
The applicant stated that industry experience indicated that SCC occurred in metal-plated BWR reactor head closure studs. The applicant stated that there are no metal-plated reactor head
 
closure studs in use, and approved lubricants are used to prevent seized studs or nuts. The
 
applicant claimed that with the lack of metal plating and preventive use of approved lubricants, Reactor Head Closure Studs Program has been effective in reducing the probability of SCC of
 
the reactor head closure studs.
The applicant concluded in its LRA that the Reactor Head Closure Studs Program provides reasonable assurance that aging effects due to cracking in the reactor head closure studs is
 
adequately managed so that their intended functions, consistent with the CLB, are maintained
 
during the period of extended operation.
The staff concluded that the reactor head closure studs are less likely to experience aging effects related to SCC, because these closure studs are not metal plated and approved
 
lubricants are used for their maintenance. The staff found the implementation of Reactor Head
 
Closure Studs Program is acceptable. Presence of aging effects can be identified by frequent
 
inspections dictated by the Reactor Head Closure Studs Program. In addition, compliance with
 
RG 1.65 requirements provides adequate assurance in maintaining the integrity of the RV studs.
 
The staff concluded that implementation of the aforementioned requirements provides assurance that the aging effect associated with SCC is adequately managed by the applicant.
3.1.2.3.13  Bolting for Reactor Vessel Vents and Drains 3-163In RAI 3.1.2.3-1(A), dated December 1, 2004, the staff stated that GALL AMP XI.M18, "Bolting Integrity Program," is recommended for managing the aging effects for the bolting in the RV
 
vents and drains. In LRA Table 3.1.2.3, the applicant indicates that the Bolting Integrity
 
Program, which is consistent with GALL AMP XI.M18, will be implemented to monitor the aging effects of the bolting in RV vents and drains. LRA Table 3.1.2.3 and the Bolting Integrity
 
Program do not identify SCC as an aging effect for these bolts. Therefore, the staff requested
 
that the applicant address the aging effect due to SCC in the bolts of the RV vents and drains.
In its response, by letter January 31, 2005, the applicant stated that SCC can occur in high yield strength (greater than 150 ksi) bolted closures in BWRs when they are exposed to a
 
corrosive environment, typically attributed to l eakage of pressure boundary joints or exposure to wetted ambient environments or due to the use of thread lubricant containing molybdenum
 
disulfide (MoS 2). High yield strength, heat-treated alloy steel bolting materials are not specified for flanged connections. High strength bolting in vendor-supplied equipment has not been
 
identified for mechanical components (such as pump casing studs or valve body/bonnet studs)
 
where the material specifications are available. The applicant stated that a review of the BFN
 
operating experience did not identify any instances where mechanical component failure was
 
attributable to SCC of high strength bolting. Therefore, loss of bolting function due to SCC of
 
bolted joints of mechanical equipment is not expected and no aging management is required for
 
the period of extended operation. Since there are no high-yield strength bolts in the RV vents
 
and drains at BFN, the staff concluded that no AMP is required to monitor the aging effect due
 
to SCC in bolting in reactor vents and drains. Therefore the staff's concern described in
 
RAI 3.1.2.3-1(A) is resolved.
3.1.2.3.14  Loss of Materials in Low Alloy Steel or Carbon Steel Reactor Vessel Components that are exposed Externally to Inside (Atmospheric) Environments The applicant identified in Table 3.1.2.1 of the LRA no aging effects, but included references related to the GALL Report Volume 2, Table IV. A1 for carbon and low-alloy steel materials of
 
the following RV components exposed externa lly to inside (atmospheric) environments.
* other external attachment welds to the reactor vessel
* reactor vessel heads, flanges, and shell
* reactor vessel nozzles
* reactor vessel nozzles and safe ends
* reactor vessel penetrations
* reactor vessel internals CRD housing
* bolting in reactor vessel vents, drains and the recirculation system The staff reviewed the applicant's evaluation to determine whether it adequately addressed the issue of uniform corrosion of the carbon and low-alloy steel RV components when they are
 
exposed externally to inside (atmospher ic) environments. According to SRP-LR Section 3.4.2.2.4, loss of material due to general corrosion can occur on the external surfaces
 
of carbon and low-alloy steel RV components exposed to operating temperature less than 212 °F. Since the operating temperature of the BWR vessel is greater than 212 °F, the loss of
 
material due to general corrosion is not likely to occur in carbon and low-alloy steel RV
 
components. In addition, the external surface of the carbon and low-alloy steel RV components
 
are exposed to inside (atmospheric) environment that does not contain any aggressive ions resulting in loss of material due to corrosion.
3-164 In RAIs 3.1.2-1, 3.1.2.1-4(A), and 3.1.2.1-5(A), dated December 1, 2004, the staff requested that the applicant provide an explanation as to why the loss of material due to corrosion is not
 
considered as an aging effect for carbon and low-alloy steel vessel attachment welds; vessel
 
heads, flanges, and shells; vessel nozzles and safe ends; vessel penetrations; and bolting in
 
vessel vents, and drains for Unit 1.
In its response to RAIs 3.1.2-1, 3.1.2.1-4(A), and 3.1.2.1-5(A), by letter dated January 31, 2005, the applicant indicated that for Unit 1 degradation due to corrosion of all the aforementioned RV
 
components would be verified under the Unit 1 restart program. The applicant also stated that it
 
will perform further inspection of the subjec t RV components followed by replacement (if required) of the degraded components that are identified by this inspection. The staff found that
 
the applicant's implementation of inspecti on and replacement programs (when necessary) provides reasonable assurance that the aging effect due to corrosion of carbon and low-alloy
 
steel penetrations for Unit 1 will be adequately managed so that the intended function(s) will be
 
maintained with the CLB for the period of extended operation.
Therefore, the staff found that these components do not experience any of the aforementioned aging effects when they are exposed externa lly to an inside (atmospheric) environment. The staff concluded that the applicant's determination to exclude these aging effects in LRA
 
Table 3.1.2.1 for the aforementioned RV components is acceptable. Therefore the staff's
 
concern described in RAIs 3.1.2-1, 3.1.2.1-4(A), and 3.1.2.1-5(A) is resolved.
3.1.2.3.15  Distortion/plastic deformation due to stress relaxation and loss of material due to mechanical wear - Reactor head closure studs and nuts; bolting in RV vents, drains and the
 
recirculation system In LRA Table 3.1.2.1, the applicant addressed distortion and plastic deformation due to stress relaxation and loss of material due to mechanical wear as aging effects in reactor head closure
 
studs and nuts. The applicant proposed to use the Reactor Head Closure Stud Program, which, in turn, invokes the requirements of GALL AMP XI.M3 to monitor this aging effect. The applicant
 
reiterated that the aforementioned aging effect is adequately managed by the ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program.
In RAI 3.1.2.1-2, dated December 1, 2004, the staff requested that the applicant identify any plant-specific aging effects due to distortion/plastic deformation resulting from stress relaxation
 
and loss of material due to mechanical wear for the reactor closure studs and nuts.
In its response to RAI 3.1.2.1-2, by letter dated January 31, 2005, the applicant stated that it has not identified any RV closure stud or nut degradation resulting in distortion/plastic
 
deformation due to stress relaxation or loss of material due to mechanical wear. The applicant
 
also stated that no RV closure studs or nuts have been replaced for this reason. Two studs
 
were replaced in Unit 2 during the Unit 2 Cycle 4 refueling outage. These were replaced
 
because of physical thread damage. From discussions with plant personnel present at that time, this damage was the result of impacts during handling and refueling operations, and not the
 
result of inservice stress or wear. Based on this, the applicant stated that there was no impact
 
on the attributes specified in the Reactor Head Closure Studs Program. The staff concluded that the proposed ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection
 
Program and Reactor Head Closure Studs Program for the reactor closure studs are consistent with GALL AMP XI.M3, and the subject aging effects are adequately managed by the applicant 3-165 for the period of extended operation. The staff finds this response acceptable, and its concern related to RAI 3.1.2.1-2 is resolved.
In LRA Table 3.1.2.3, the applicant addressed loss of bolting function due to wear as an aging effect in RV vents and drains and the recirculation system. The applicant proposed to use the
 
Bolting Integrity Program for monitoring this aging effect, which in turn, invokes the requirements of GALL AMP XI.M18. GALL AMP XI.M18 requires application of ASME CodeSection XI Subsection IWB, Table IWB 2500-1 for the bolts that are included in the ASME Code Section XI Program to monitor this aging effect. In addition, the aging effects for the SR bolting
 
are mitigated by NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation Failure in Nuclear Power Plants." For bolts that are not included in the ASME Section XI
 
program, the applicant proposed to use the Sy stems Monitoring Program. The staff concluded that the implementation of the Bolting Int egrity Program and Systems Monitoring Program, andcompliance with GALL AMP XI.18 will provide reasonable assurance that loss of bolting function
 
due to wear in RV vents and drains and the recirculation system is adequately managed so that
 
their intended functions, consistent with the CLB, are maintained during the period of extended
 
operation.
In RAI 3.1.2.3-1(B), dated December 1, 2004, the staff requested that the applicant provide information on the previous plant-specific experience of loss of bolting function due to wear in
 
the RV vents and drains system. The staff also requested that the applicant provide information on the scope and the techniques of the past inspections, the results obtained, applied mitigative
 
methods, repairs, frequency of the inspections and any other relevant information related to the
 
identification of this aging effect of the bolts in RV vents and drains. In addition, the staff
 
requested that the applicant provide information as to how the plant-specific experience related
 
to this aging effect impacts the attributes specified in the Bolting Integrity Program.
In its response to RAI 3.1.2.3-1(B), by letter dated January 31, 2005, the applicant stated that aging effect due to wear was conservatively identified to be an aging effect that requires
 
management for the period of extended operation for pressure boundary bolting in RV vents
 
and drains. The applicant also stated that these bolts are inspected in accordance with ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program inspection
 
requirements, and the Systems Monitori ng Program. The Systems Monitoring Program performs an entire system inspection once per fuel cycle and includes visual inspections for
 
evidence of material condition and bolting torque relaxation. The Systems Monitoring Program
 
documents failures in either the maintenance work order or plant corrective action program, as
 
appropriate. The applicant indicated that so far, no instances of RV vents and drains bolting
 
failure due to wear have been identified. The staff finds this response acceptable, and its
 
concern related to RAI 3.1.2.3-1(B) is resolved.
 
In RAI 3.1.2.4-1(A), dated December 1, 2004, the staff requested that the applicant provide
 
information on the previous plant-specific experience of loss of bolting function due to stress
 
relaxation in the RV recirculation system. The staff also requested that the applicant provide
 
information on the scope and the techniques of the past inspections, the results obtained, applied mitigative methods, repairs, frequency of the inspections, and any other relevant
 
information related to the identification of this aging effect of the RV recirculation system bolts.
 
In addition, the staff requested that the applicant provide information as to how the plant-specific
 
experience related to this aging effect impacts the attributes specified in the Bolting Integrity
 
Program.
3-166 In its response to RAI 3.1.2.4-1(A), by letter dated January 31, 2005, the applicant stated that it inspected the reactor water recirculation pump closure bolting in accordance with the requirements of ASME Section XI, Table IWB-2500-1, Category B-G-1. The inspection methods
 
included visual examination and UT, and the results were acceptable. Therefore, the applicant
 
did not perform any repair on the reactor recirculation pump closure bolting. The applicant
 
stated that implementation of AMP B.2.1.16, and compliance with the recommendations of
 
NUREG-1339 and EPRI NP-5769 provide adequate assurance that the aging effect due to
 
stress relaxation in the bolting of the RV recirculation system is effectively managed for the
 
extended period of operation.
The staff reviewed the applicant's responses to the above RAIs, and concluded that theimplementation of ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection
 
Program, Bolting Integrity Program, and Systems Monitoring Program is consistent with GALLAMP XI.M18 and the subject aging effects for bolting in RV vents, drains and the recirculation
 
system are adequately managed at BFN. Therefore, the staff's concerns described in the above
 
RAIs are resolved.
3.1.2.3.16  Crack Initiation and Growth Due to Stress Corrosion Cracking, Fatigue and Cyclic Loading The staff's evaluation of the aging effect due to cyclic loading and fatigue is discussed in SER Section 3.1.2.2.4.
AMPs recommended by the GALL Report for managing cracking due to IGSCC for the RVinternal components are XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," XI.M2, "Water Chemistry," and XI.M9, "BWR Vessel Internals." AMP XI.M9 includes implementation of guidelines specified in the staff-approved BWRVIP documents for a given
 
component.
In LRA Table 3.1.2.2, the applicant identified SCC as an aging effect in (1) RVIs core shroud and core plate, (2) RVIs core spray and feedwater spargers, (3) RVIs control rod housing and
 
dry tubes and guide tubes, (4) RVIs jet pump assemblies, and (5) RVIs top guide.
In LRA Table 3.1.2.2, the applicant stated that the aging effect due to SCC in the aforementioned components is managed by (1) Boiling Water Reactor Vessel Internals Program, (2) ASME Code Section XI Subsections IWB, IWC, and IWD ISI Program, and (3) the
 
Chemistry Control Program. The applicant stated that continued implementation of these AMPs provides reasonable assurance that the aging effects due to SCC, fatigue, and cyclic loading
 
will be managed so that the systems and component s within the scope of this program will continue to perform their intended functions consistent with the CLB for the period of extended
 
operation.
In RAI 3.1.2.1-6(A), dated December 1, 2004, the staff requested that the applicant provide information on the scope and the techniques of the past inspections, the results obtained, applied mitigative methods, repairs, and frequency of the inspections of the AHCs. In response to RAI 3.1.2.1-6(A), by letter dated January 31, 2005, the applicant stated that the Unit 1 core
 
shroud AHCs currently have indications of cracking and will be replaced with a bolted design in
 
lieu of a welded design prior to Unit 1 restart. Units 2 and 3 AHCs have no reportable 3-167 indications. In addition, the applicant stated that the improvements in the RCS Chemistry Control Program would enable the mitigation of IGSCC of the AHCs.
In RAI B.2.1.12-1(C), dated December 1, 2004, the staff requested the applicant to provide information regarding any prior augmented UT for the AHCs as required by GALL Report Section IV-B1.1.4. In its response, by letter January 31, 2005, the applicant stated that the
 
AHCs are examined in accordance with GE SIL No. 462, Revision 1. The GE SIL allows for
 
inspection of the AHCs either by UT or top-surface visual (VT-1) inspection. The applicant has
 
always used the UT technique, as this methodol ogy provides superior flaw detection and allows for a longer reinspection interval. Due to tooling constraints, a top-surface enhanced VT-1 (EVT-1), which is superior to the visual examination guidelines of GE SIL No. 462, was
 
performed for Unit 3 AHCs. The applicant stated that prior to the period of extended operation, it
 
will implement visual inspection of the AHCs and inspection of the AHC welds by UT, unless
 
tooling constraints prohibit performance of a UT. In the event tooling constraints prohibit
 
inspection by UT, the inspection will be performed by EVT-1. The applicant proposed to inspect the AHCs utilizing the BWR Vessel Internals Program rather than the ASME Code Section XI
 
ISI Program currently specified in the GALL Report. SER Section 3.0.3.2.7 presents the staff's
 
detailed review of this AMP.
Since the GALL Report Section IV-B1.1.4 requires UT of AHC welds, the staff requested that the applicant revise BWR Vessel Internals Program and LRA Section A.1.12 to include UT for
 
Units 2 and 3 AHC welds to the maximum extent possible. The staff requested that the applicant
 
identify its previous experience on the extent to which UT was performed on the AHC welds.
The applicant, in its response dated May 25, 2005, stated that Unit 1 welded AHCs will be replaced by a bolted design thereby eliminating the need for UT. However, Units 2 and 3 will still
 
have welded AHCs and they require UT examination. The applicant stated that UT
 
examinations had been performed on the AHC welds in Units 2 and 3, and thus far no
 
indications had been identified. The applicant stated that it will perform UT on AHC welds at
 
Units 2 and 3 unless tooling constrains prohibit inspections by UT, in which case it will perform
 
EVT-1 examinations. The applicant stated that it will obtain prior approval from the staff if EVT-1
 
is substituted for UT examination of the welded AHCs at Units 2 and 3. The staff found this
 
response acceptable, because previous UT examinations of AHC welds at Units 2 and 3
 
indicated no evidence of cracks and as such there is no evidence of active degradation in the
 
AHC welds at Units 2 and 3. Additionally, the applicant stated that it will perform UT
 
examinations on accessible AHC welds and EVT-1 examinations in inaccessible AHC welds, and these examinations will adequately identify the cracks in AHC welds at Units 2 and 3. The
 
staff accepts the applicant's response as a commitment and concludes that it should be
 
included in the commitment tables in lieu of LRA Section A.1.12. Based on its review, the staff's
 
concerns described in RAIs 3.1.2.1-.6(A), and B-2.1.12-1(C) are resolved.
In RAI 3.1.2.1-6(B), dated December 1, 2004, the staff requested that the applicant provide an explanation for excluding the aging effect due to IASCC for the core shroud and core plate. In
 
its response to RAI 3.1.2.1-6(B), by letter dated January 31, 2005, the applicant stated that it
 
will include the aging effect due to IASCC in LRA Table 3.1.2.2, and this aging effect is managed by implementing the ASME Code Section XI Subsections IWB, IWC, and IWD and
 
Chemistry Control Programs. The BWR Vessel Internals Program invokes inspection
 
requirements specified in BWRVIP-76, "Boiling Water Reactor Core Shroud Inspection and
 
Flaw Evaluation Guidelines," which is currently being reviewed by the staff. In the BWR Vessel 3-168 Internals Program, the applicant stated that it w ill comply with all the requirements that will be specified in the staff's SER on the BWRVIP-76 report, and will complete all the license renewal
 
applicant action items of this SER when it is issued. The staff reviewed the response and found
 
it acceptable because the implementation of the inspections as mandated by the ASME CodeSection XI Subsections IWB, IWC, and IWD Program and BWRVIP-76 (pending staff's
 
approval) should identify any cracking due to IASCC in a timely manner so that the intended
 
function of the subject component is maintained during the extended period of operation.
In RAI 3.1.2.1-6(C), dated December 1, 2004, the staff requested the applicant to provide information regarding the plant-specific experience related to IGSCC cracking of the stainless
 
steel and nickel-alloy components in the core shroud and AHCs, and the effective AMP that will
 
be implemented on these systems. In its res ponse to RAI 3.1.2.1-6(C), by letter dated January 31, 2005, the applicant stated that indications have been reported in Unit 1 core shroud
 
welds H-1, H-2, H-3, H-4, and H-5. Core shroud welds H-6 and H-7 have not been examined
 
due to interference from vibration sensing lines. These welds will be UT examined prior to Unit 1
 
restart. Indications have been reported in Unit 2 core shroud welds H-1, H-2, H-3, H-5, H-6, and
 
H-7. Indications have been reported in Unit 3 core shroud welds H-1, H-2, H-3, H-4, H-5, and
 
H-7. The applicant stated that the aging effect due to IGSCC is managed by AMPs BWR Vessel Internals, ASME Code Section XI Subsections IWB, IWC, and IWD, and Chemistry Control
 
Programs. The staff finds this response acceptable, and its concern related to RAI 3.1.2.1-6(C)
 
is resolved.
In RAI 3.1.2.1-6(D), dated December 1, 2004, the staff requested the applicant to address the plant-specific experience regarding sudden increases in RCS water conductivity due to a leak in condensate and/or reactor water clean up systems, and the impact of these sudden conductivity
 
excursions on the IGSCC of core shroud welds. In its response to RAI 3.1.2.1-6(D), by letter
 
dated January 31, 2005, the applicant stated that there had been no increase in conductivity in
 
RCS water due to leaks in condensate and/or reactor water clean up systems in the previous
 
five years. The staff found that in the absence of any increase in RCS water conductivity, and
 
with the addition of hydrogen/noble metal to the RCS water, the growth of existing IGSCC in the
 
core shroud welds will be mitigated. The staff finds this response acceptable, and its concern
 
related to RAI 3.1.2.1-6(D) is resolved In RAI 3.1.2.1-6(E), dated December 1, 2004, the staff requested the applicant to provide information on verification methods to monitor the effectiveness of the HWC/NMCA program, the methodology of ensuring hydrogen availability in the core shroud region, monitoring of its
 
availability with ECP probes, and the validity of using secondary parameters (e.g., main
 
steam/feedwater oxygen levels) to assess the hydrogen availability at core shroud welds. In its
 
response to RAI 3.1.2.1-6 (E), by letter dated January 31, 2005, the applicant stated that an
 
NMCA with a conservative hydrogen/oxygen (H 2/O 2) molar ratio is maintained to ensure hydrogen availability in the core shroud region. The applicant stated that it would not utilize ECP
 
probes; therefore, alternate means are used to monitor ECP. The applicant proposed to use
 
reactor water H 2/O 2 molar ratio of greater than four for power operation. The staff reviewed the response and found it acceptable because, in the absence of ECP measurements, maintaining
 
a H 2/O 2 molar ratio of greater than four would be effective in mitigating IGSCC in core shroud welds. The staff found that the implementation of t he improved water chemistry and ISI programs in conjunction with the inspection guidelines specified in the BWRVIP-76 report (pending staff's 3-169 approval) would enable the applicant to manage the aging effect due to IGSCC effectivelyduring the extended period of operation, and would be consistent with GALL AMPs XI.M1, XI.M2 and XI.M9.
In RAI 3.1.2.2-7(A), dated December 1, 2004, the staff requested the applicant to provide an explanation for excluding the aging effect due to IASCC for the core spray spargers and piping
 
in LRA Table 3.1.2.2. According to GALL Report Section IV B1.3-a, an AMP is required for
 
monitoring IASCC in core spray spargers and piping. In its response, by letter dated January 31, 2005, the applicant stated that it will include aging effect due to IASCC in LRA Table 3.1.2.2, and this aging effect is managed by implementing the ASME Code Section XI Subsections IWB, IWC, and IWD, BWR Vessel Internals, and Chemistry Control Programs.
In RAI 3.1.2.2-7(B), dated December 1, 2004, the staff requested the applicant to provide information on the type and extent of inspections to identify IGSCC and the mitigation
 
techniques for core spray piping and spargers at Units 2 and 3. In its response, by letter dated
 
January 31, 2005, the applicant stated that the inspections (the type and extent) were
 
performed in accordance with the requirements of BWRVIP-18, "BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines," and ASME Code Section XI Subsections IWB, IWC, and IWD, BWR Vessel Internals. The applicant stated that thus far no cracking was
 
identified in the core spray system with the following exceptions. The applicant stated that it
 
identified cracking in the elbow-to-shroud pipe and collar-to-shroud welds in downcomer "C" in
 
Unit 3, which was subsequently replaced with a bolted piping assembly as a corrective action.
 
The applicant identified cracking in Unit 3 core spray sparger adjacent to the T-boxes, which
 
was repaired by welded brackets at both T-boxes. The applicant indicated that mitigation of
 
IGSCC in core spray piping and spargers w ould be achieved by the implementation of HWC/NMCA.
The staff, after reviewing BWRVIP-18, concluded that core spray piping and spargers are not adequately protected by the HWC/NMCA. However, implementation of the inspection guidelines as required by BWRVIP-18 and ASME Code Section XI Subsections IWB, IWC, and IWD, will
 
inadequately identify cracking in a timely manner. Therefore, the staff concluded that the type
 
and extent of inspections mandated by BWRVIP-18 and the ISI Program should adequately
 
identify cracking (without taking any credit for HWC/NMCA) in core spray piping and spargers in
 
a timely manner so that their intended function is maintained during the period of extended operation. Since the applicant is implementing the ASME Code Section XI Subsections IWB, IWC, and IWD, BWR Vessel Internals Program and Chemistry Control Program, which are consistent with the GALL AMP XI.M9, the staff found that the applicant had demonstrated that
 
the effects of aging in core spray piping and spargers will be adequately managed for the period
 
of extended operation.
In RAI 3.1.2.2-8(A), dated December 1, 2004, the staff requested the applicant to provide an explanation for excluding the aging effect due to IASCC for the CRD housing dry tubes and
 
guide tubes in Table 3.1.2.2 of the LRA. In its response, by letter dated January 31, 2005, the
 
applicant stated that it will include aging effect due to IASCC in LRA Table 3.1.2.2, and that this aging effect is managed by implementing ASME Code Section XI Subsections IWB, IWC, and
 
IWD, BWR Vessel Internals Program and Chemistry Control Program. BWR Vessel Internals
 
Program in turn invokes inspection requirements specified in BWRVIP-47, "Boiling Water
 
Reactor Lower Plenum Inspection and Flaw Evaluation Guidelines." The staff reviewed the
 
response and found it acceptable because the implementation of the inspections as mandated 3-170by the ASME Code Section XI Subsections IWB, IWC, and IWD Program and BWRVIP-47 should identify any cracking due to IASCC in a timely manner so that the intended function of
 
the subject component is maintained during the period of extended operation. Therefore, the
 
staff's concern described in RAI 3.1.2.2-8(A) is resolved.
In RAI 3.1.2.2-8(B), dated December 1, 2004, the staff requested the applicant to provide information regarding the past plant-specific experience related to IGSCC in the nickel-alloy
 
housing guide tubes and dry tubes and their subsequent replacement with crack-resistant
 
materials at Units 2 and 3. The staff also requested that the applicant provide its plan for the
 
replacement of Unit 1 dry tubes and guide tubes. In its response, by letter dated January 31, 2005, the applicant stated that all 12 Unit 2 and 3 radiation monitor dry tubes had been replaced
 
with a crevice-free design in the plunger area. Additionally, the material in the plunger area had
 
been changed from 304 stainless steel to 304L stainless steel, making the new dry tubes less
 
susceptible to IGSCC.
The applicant in its response dated May 25, 2005, stated that it will replace Unit 1 dry tubes prior to restart. However, the applicant must commit to replace all Unit 1 dry tubes prior to
 
restart. This commitment would be contained in a tracking process either for Unit 1 restart or
 
license renewal.
Based on its assessment of Unit 2 Cycle 7 refueling outage and Unit 3 prior to its restart in 1995 (see RAI response dated December 1, 2004), the applicant found that the plant-specific
 
experience related to the dry tubes has no impact on the attributes specified in the BWR Vessel
 
Internals Program and BWRVIP-47. The staff reviewed the applicant's response and concluded
 
that the replacement of the dry tubes material that is more IGSCC resistant combined with new
 
crevice-free design provides adequate assurance that the aging effect due to IGSCC in these
 
components is adequately managed for the period of extended operation. The staff found this
 
response acceptable, and its concern related to RAI 3.1.2.2-8(B) is resolved.
In RAI 3.1.2.2-8(C), dated December 1, 2004, the staff requested that the applicant provide information regarding the plant-specific experience related to IGSCC in furnace-sensitized
 
stainless steel stub tubes (if any) at BFN, and the method and frequency of inspections to
 
identify this aging effect. In its response to RAI 3.1.2.2-8(C), by letter dated January 31, 2005, the applicant stated that BFN does not have furnace-sensitized stainless steel stub tubes and
 
the stub tubes are manufactured from a nickel alloy. The applicant also stated that there have
 
been no repairs associated with the CRD stub tubes, and improvements in the BWR Chemistry
 
Control Program help mitigate aging and degradation of the lower plenum components. Based
 
on this assessment, the applicant stated that the plant-specific experience related to the stub
 
tubes has no impact on the attributes specified in the BWR Vessel Internals Program and
 
BWRVIP-47 as no degradation has been identified. The staff concurred with the applicant's
 
response and found it acceptable. Therefore, the staff's concern described in RAI 3.1.2.2-8(C)
 
is resolved.
In RAI 3.1.2.2-8(D), dated December 1, 2004, the staff requested that the applicant provide information regarding the plant-specific experience related to IGSCC cracking in nickel-alloy
 
weld metals that were used for the CRD stub tubes, and the method and frequency of
 
inspections to identify this aging effect. In its response, by letter dated January 31, 2005, the
 
applicant identified the following locations associated with the lower plenum that have
 
nickel-alloy weld metal.
3-171
* CRD housing-to-stub tube weld
* CRD stub tube-to-RV weld
* In-core housing-to-RV lower head penetration weld
* In-core guide tube-to-in-core housing weld The applicant stated that its AMR does not identify an inspection of the listed welds, and no cracking has been identified at BFN for the listed nickel-alloy welds. The applicant also stated
 
that the improvements in the BWR Chemis try Control Program help mitigate aging and degradation of the lower plenum components. Therefore, the applicant claimed that the
 
plant-specific experience related to the lower plenum nickel-alloy welds has no impact on the
 
attributes specified in the BWR Vessel Internals Program and BWRVIP-47 as no degradation
 
has been identified. The staff found the applicant's response acceptable.
The staff concluded that the implementation of the inspection requirements as mandated by the ISI program and the staff's approved BWRVIP-47 report will provide reasonable assurance that IGSCC in the lower plenum welds can be identified in a timely manner, so that the intended
 
function of the subject component is maintained during the period of extended operation.
In RAI 3.1.2.2-10, dated December 1, 2004, the staff requested the applicant to provide an explanation for excluding the aging effect due to IASCC for the top guide. The applicant in its
 
response indicated that it will include IASCC as an aging effect for the top guide in LRA
 
Table 3.1.2.2. SER Section 4.7.6 on TLAA discusses the impact of IASCC and multiple failures
 
of the top guide grid beams at BFN.
The staff requested that the applicant in its LRA provide the AMR for the jet pump thermal sleeve welds in order to comply with the requirement specified in BWRVIP-41, Appendix A, paragraph A.2, "BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines," report.
 
In its response dated May 25, 2005, the applicant stated that it implemented the Chemistry
 
Control Program and the BWR Vessel Internals Program to monitor the aging effects in jet
 
pump thermal sleeve welds. The applicant stated that the inspection requirements of the
 
BWRVIP-41 report are included in the BWR Vessel Internals Program; and that they will
 
adequately manage aging degradation due to fatigue in jet pump thermal sleeve welds. The
 
applicant further stated that the jet pump thermal sleeve welds are not inspectible with existing
 
techniques; however, it will implement an inspec tion technique that is currently being developed by the BWRVIP, when available. The staff found this response acceptable because the
 
applicant has committed to implement BWRVIP-41 and the BWRVIP is currently developing an
 
inspection technique that will enable the applicant to adequately identify cracking due to fatigue
 
or IGSCC. Therefore, the staff's concern described in RAI 3.1.2.2-10 is resolved.
 
3.1.2.3.17  Change in Material Properties and Reduction in Fracture Toughness Due to Thermal
 
Aging and Neutron Irradiation Embrittlement The AMP recommended by the GALL Report for managing the susceptibility of CASS components to thermal aging embrittlement and neutron irradiation embrittlement is AMPXI.M13, "Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS)."In LRA Table 3.1.2.2, the applicant stated that the aging effects due to change in material properties as a result of thermal and neutron embrittlement of the CASS RVIs jet pump 3-172 assemblies will be managed by the Thermal Aging and Neutron Irradiation Embrittlement ofCast Austenitic Stainless Steel Program, ASME Code Section XI Subsections IWB, IWC, and
 
IWD Inservice Inspection Program, Boiling Water Reactor Vessel Internals Program, and the
 
inspection guidelines that are provided in the BWRVIP-41, "BWR Jet Pump Assembly
 
Inspection and Flaw evaluation guidelines," which have been approved by the staff. The
 
implementation of these programs is consistent with the GALL AMP XI.M13, and the applicant did not take any exception to the requirements of the GALL Report. The applicant incorporated
 
a screening criterion that establishes susceptibility of CASS components to thermal aging based
 
on casting method, molybdenum content, and ferrite percentage.
In RAI 3.1.2.2-9, dated December 1, 2004, the staff requested the applicant to provide information on the existing (if any) CASS jet pump components, the type of casting, composition of the CASS (i.e., molybdenum content and delta ferrite values), previous plant-specific
 
experience regarding the cracked components with subsequent inspection of any cracked
 
CASS jet pump components due to neutron and t hermal embrittlement, and any technical specification changes related to jet pump components.
In its response, by letter dated January 31, 2005, the applicant indicated that the CASS jet pump components were manufactured to ASTM A351, grade CF8. These castings are low
 
molybdenum and the maximum calculated delta ferrite percentage is below 20 percent.
 
According to Table 2, CASS Thermal Aging Susceptibility Screening Criteria, contained in the
 
May 19, 2000, NRC letter from Christopher Grimes to Douglas J. Walters, materials that have a
 
low molybdenum content and less than 20 percent delta ferrite are not susceptible to thermal
 
aging for statically or centrifugally cast components. The NRC letter from Christopher Grimes to
 
Carl Terry, dated June 5, 2001, states, "It is important to note that thermal and/or neutron
 
embrittlement of CASS components becomes a concern only if cracks are present in the
 
components, and that cracking has not been observed in CASS jet pump assembly
 
components." Section 2.4 of the same letter states, "Further, the BWRVIP and the NRC's Office
 
of Nuclear Regulatory Research (RES) is engaged in a joint confirmatory research program to
 
determine the effects of high levels of neutron fluence on BWR internals." The applicant has
 
stated in its LRA that for open issues between the BWRVIP and NRC, the applicant will work as
 
part of the BWRVIP to resolve these issues generically. When resolved, the applicant will follow
 
the BWRVIP recommendations resulting from that resolution. The BWR RVIs program requires
 
inspections of several jet pump assembly welds which are more susceptible to cracking than the
 
CASS components and will serve as an indication of the potential need for more extensive
 
inspections later in life.
Similar to the CASS jet pump components, the orificed fuel supports (OFS) are also manufactured to ASTM A351, grade CF8. These castings are low molybdenum and the
 
maximum calculated delta ferrite percentage is below 20 percent. For reasons similar to those
 
as discussed for the jet pump CASS components, the applicant concluded that no program is
 
needed to manage the effects of thermal/neutron embrittlement of the CASS OFS.
The staff concurred with the applicant's response regarding the implementation of the industry-recommended monitoring program of the effects of high levels of neutron fluence on
 
the CASS components. The staff concluded that the applicant's justification for excluding the
 
CASS jet pumps and OFS components from the AMR for the extended period of operation is acceptable provided that ASME Code Section XI Subsections IWB, IWC, and IWD Program and
 
the BWR Vessel Internals Program and inspection requirements of BWRVIP-41 are fully 3-173 implemented for these components. The staff concurred with the applicant's statement that continued implementation of these AMPs and the technical guidelines of the BWRVIP-41 report
 
provide reasonable assurance that the aging effects are adequately managed in the RV CASS
 
jet pumps and OFS components. The staff found this response acceptable, and its concern
 
related to RAI 3.1.2.2-9 is resolved.
3.1.2.3.18  Loss of Material Due to Galvanic, General, Crevice, and Pitting Corrosion
 
In LRA Table 3.1.2.2, the applicant addressed loss of material due to galvanic, general, crevice, and pitting corrosion in (1) RVIs core shroud and core plate, (2) RVIs core spray piping and
 
spargers, (3) RVIs control rod housing and dry tubes and guide tubes, (4) RVIs jet pump
 
assemblies, and (5) RVIs top guide.
 
The applicant also identified the implementation of relevant AMPs to manage the aging effects
 
due to galvanic, general, crevice, and pitting corrosion of stainless steel and nickel-alloy
 
materials when these materials are exposed to the BWR treated-water environment. In LRA
 
Table 3.1.2.2, the applicant included AMP requirements that are specified in GALL Report, Volume 2, Table IV.B1 for each of the aforementioned components. However, GALL Report, Volume 2, Table IV.B1, does not identify loss of material due to crevice, general, and pitting
 
corrosion as aging effects in stainless steel and nickel-alloy materials that are used in the
 
aforementioned RV components when these components are exposed to the BWR
 
treated-water environment. The staff's evaluation of the AMR related to these aging effects is
 
discussed below.
 
In LRA Table 3.1.2.2, the applicant stated that the aging effects due to galvanic, general, crevice, and pitting corrosion of stainless steel and nickel-alloy materials in the RVIs will be
 
managed by the Boiling Water Reactor Vessel Inte rnals Program, Chemistry Control Program, and the inspection guidelines that are provided in the following BWRVIP reports for the
 
applicable internal components:
BWRVIP "Boiling Water Reactor Core Spray Internal Inspection and Flaw Evaluation Guidelines." BWRVIP "Boiling Water Reactor Core Plate Inspection and Flaw Evaluation Guidelines." BWRVIP "Boiling Water Reactor Top Guide Inspection and Flaw Evaluation Guidelines." BWRVIP "Boiling Water Reactor Jet Pump Assembly Inspection and Flaw Evaluation Guidelines." BWRVIP "Boiling Water Reactor Lower Plenum Inspection and Flaw Evaluation Guidelines." BWRVIP "Boiling Water Reactor Core Shroud Inspection and Flaw Evaluation Guidelines" - Staff review is not complete.
3-174 The implementation of these additional guidelines and AMPs is consistent with GALLAMP XI.M9. The applicant stated that conti nued implementation of these AMPs provides reasonable assurance that the aforementioned aging effects are adequately managed in the
 
RVIs. The staff concluded that the implementation of the Chemistry Control Program will provide adequate controls on BWR reactor water chemistry, which in turn controls general, pitting and
 
crevice corrosion in RVIs. Furthermore, inspection guidelines that are specified in the
 
aforementioned staff-approved (with the exception of BWRVIP-76) BWRVIP reports will provide adequate guidance in performing the necessary inspections so that these aging effects in RVIs
 
are properly identified in a timely manner.
In LRA Table 3.1.2.1, the applicant addressed loss of material due to galvanic, general, crevice, and pitting corrosion in (1) reactor head closure studs, (2) RV attachment welds, (3) RV heads, flanges and shells, (4) RV nozzles, (5) RV nozzles and safe ends, (6) RV penetrations, and (7)
 
bolting in RV vents, drains, and the recirculation system.
The applicant also identified the implementation of relevant AMPs to manage the aging effects due to galvanic, general, crevice, and pitting corrosion of carbon and low-alloy steels, stainless
 
steel and nickel-alloy materials when these materials are exposed to the BWR treated-water
 
environment. In LRA Table 3.1.2.1, the applicant identified these aging effects and the relevant
 
AMPs that are associated with each of the aforementioned components. In LRA Table 3.1.2.1, the applicant also included references related to GALL Report, Volume 2, Table IV.A1 for each
 
of the aforementioned components.
GALL Report, Volume 2, Table IV.A1, does not identify loss of material due to crevice, general, and pitting corrosion as aging effects in carbon and low-alloy steel, stainless steel and
 
nickel-alloy materials that are used in the aforementioned RV components when these
 
components are exposed to the BWR treated-wate r environment. General, pitting, and crevice corrosion may occur in stainless steel or nickel-alloy components under exposure to aggressive, oxidizing environments. Normally, the presenc e of elevated dissolved oxygen and/or aggressive ionic impurity concentrations is necessary to create these oxidizing environments in the RCS.
The applicant stated that the Chemistry Control Program will be used at BFN. The Chemistry Control Program is based on EPRI Report TR-103515-R2 (the 2000 revision of "BWR Water
 
Chemistry Guidelines"). The staff found EPRI TR-103515-R2 acceptable because the program
 
is based on updated industry experience and plant-specific and industry-wide operating
 
experience confirms the effectiveness of the Chemistry Control Program. In addition, this program provides an acceptable basis for mi nimizing the dissolved oxygen and ionic impurity concentrations that could otherwise, if left present in high concentrations, lead to an aggressive
 
oxidizing RCS coolant environment, which can enhance corrosion of the RV components. Since
 
the applicant has conservatively assumed that loss of material due to general corrosion, pitting
 
corrosion, or crevice corrosion is an applicable aging effect for these RV components, the staff
 
concludes that the Chemistry Control Program provides a sufficient mitigative strategy for managing this aging effect relative to the recommendations of the GALL Report. The applicant stated that it will invoke ASME Code Section XI Subsections IWB, IWC, and IWD Inservice
 
Inspection Program, which is an established AM P. This program has appropriate requirements for inspecting the aforementioned vessel components. The staff concluded that by implementing the ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program and Chemistry Control Program, the applicant 3-175 demonstrated that the effects of aging due to general, pitting, and crevice corrosion will be adequately managed so that the intended functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff found that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluated AMR results involving MEAP combinations that are not evaluated in the GALL Report. The staff
 
found that the applicant demonstrated that the effects of aging will be adequately managed so
 
that the intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
 
====3.1.3 Conclusion====
The staff concluded that the applicant provided sufficient information to demonstrate that the effects of aging of the reactor vessel internals and reactor coolant system components that are
 
within the scope of license renewal and subject to an AMR, will be adequately managed so that
 
the intended function(s) will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
The staff also reviewed the applicable UFSAR supplement program summaries and concluded that they adequately describe the AMPs credited for managing aging of the reactor vessel, internals, and reactor coolant system, as required by 10 CFR 54.21(d).
3-1763.2  Aging Management of Engineered Safety Features This section of the SER documents the staff's review of the applicant's AMR results for the ESF systems components and component groups a ssociated with the following systems:
* containment
* standby gas treatment
* high pressure coolant injection
* residual heat removal
* core spray
* containment inerting
* containment atmosphere dilution3.2.1  Summary of Technical Information in the Application In LRA Section 3.2, the applicant provided AMR results for components. In LRA Table 3.2.1,"Summary of Aging Management Evaluations for Engineered Safety Features Evaluated in Chapter V of NUREG-1801," the applicant provided a summary comparison of its AMRs with the
 
AMRs evaluated in the GALL Report for t he ESF systems components and component groups.
The applicant's AMRs incorporated applicable operating experience in the determination of AERMs. These reviews included evaluation of plant-specific and industry operating experience.
 
The plant-specific evaluation included reviews of condition reports and discussions with
 
appropriate site personnel to identify AERMs. The applicant's review of industry operating
 
experience included a review of the GALL Report and operating experience issues identified
 
since the issuance of the GALL Report.
 
====3.2.2 Staff====
Evaluation The staff reviewed LRA Section 3.2 to determine whether the applicant had provided sufficient information to demonstrate that the effects of aging for the ESF systems components that are
 
within the scope of license renewal and subject to an AMR will be adequately managed so that
 
the intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
The staff performed an onsite audit, during the weeks of June 21 and July 2, 2004, of AMRs to confirm the applicant's claim that certain identified AMRs are consistent with the GALL Report.
 
The staff did not repeat its review of the matters described in the GALL Report; however, the
 
staff did verify that the material presented in the LRA was applicable and that the applicant had
 
identified the appropriate GALL AMRs. The staff's evaluations of the AMPs are documented in
 
SER Section 3.0.3. Detail of the staff's audit evaluation are documented in the BFN audit and
 
review report and are summarized in SER Section 3.2.2.1.
In the onsite audit, the staff also selected AMRs that are consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further
 
evaluations are consistent with the acceptance criteria in SRP-LR Section 3.2.2.2, dated
 
July 2001. The staff's audit evaluations are documented in the BFN audit and review report and
 
are summarized in SER Section 3.2.2.2.
3-177 In the onsite audit, the staff also conducted a technical review of the remaining AMRs that are not consistent with, or not addressed in, the GALL Report. The audit and technical review
 
included evaluating whether all plausible aging effects had been identified and evaluating
 
whether the aging effects listed were appropriate for the combination of materials and
 
environments specified. The staff's audit evaluations are documented in the BFN audit and
 
review report and are summarized in SER Section 3.2.2.3. The staff's evaluation of its technical
 
review is also documented in Section SER 3.2.2.3.
Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or
 
monitoring aging for the ESF systems components.
Table 3.2-1, below, provides a summary of the staff's evaluation of components, aging effects/mechanisms, and AMPs listed in LRA Section 3.2 that are addressed in the GALL
 
Report.Table 3.2-1  Staff Evaluation for Engineered Safety Features System Components in the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation Piping, fittings and valves in emergency core cooling system (Item Number
 
3.2.1.1)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAAThis TLAA is evaluated in
 
Section 4.3, Metal Fatigue Piping, fittings, pumps and valves in emergency core cooling system (Item Number
 
3.2.1.2)Loss of material due to general corrosion Water ChemistryProgram; One-Time
 
Inspection ProgramChemistry ControlProgram; One-Time
 
Inspection ProgramConsistent withGALL which
 
recommends further
 
evaluation (See
 
Section  3.2.2.2.2)
Components in containment spray (PWR only),
standby gas treatment system (BWR only),
containment
 
isolation, and emergency core cooling systems (Item Number
 
3.2.1.3)Loss of material due to general corrosionPlant-specificOne-Time Inspection Program; Chemistry Control Program; Systems
 
Monitoring Program See Section 3.2.2.2.2 Containment isolation valves and
 
associated piping (Item Number
 
3.2.1.6)Loss of material due to microbiologically
 
influenced corrosion (MIC)Plant-specificOpen-Cycle CoolingWater Program See Section 3.2.2.2.4 Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-178 Seals in standby gas treatment system (Item Number
 
3.2.1.7)Changes in properties due to
 
elastomer degradationPlant-specificN/ASee Section 3.2.2.2.5Drywell and suppression
 
chamber spray system nozzles and flow orifices (Item Number
 
3.2.1.9)Plugging of nozzlesand flow orifices by
 
general corrosion
 
productsPlant-specificN/ASee Section 3.2.2.2.7 External surface of carbon steel
 
components (Item Number
 
3.2.1.10)Loss of material due to general corrosionPlant-specificOne-Time Inspection Program; Chemistry Control Program; Systems
 
Monitoring Program See Section 3.2.2.2.2 Piping and fittings of CASS in emergency
 
core cooling systems (Item Number
 
3.2.1.11)Loss of fracture toughness due to
 
thermal aging
 
embrittlementThermal Aging Embrittlement of
 
CASS ProgramN/ANot ApplicableBFN does not
 
require a thermal
 
aging embrittlement
 
of CASS AMP Components serviced by open-cycle cooling system (Item Number
 
3.2.1.12)Loss of material due to general, pitting, and crevice
 
corrosion, MIC, and
 
biofouling; buildup
 
of deposit due to
 
biofoulingOpen-Cycle CoolingWater System
 
ProgramOpen-Cycle CoolingWater System
 
ProgramConsistent withGALL which
 
recommends no
 
further evaluation (See Section
 
3.2.2.1)Components serviced by closed-cycle cooling system (Item Number
 
3.2.1.13)Loss of material due to general, pitting, and crevice
 
corrosionClosed-CycleCooling Water System ProgramClosed-CycleCooling Water System ProgramConsistent withGALL which
 
recommends no
 
further evaluation (See Section
 
3.2.2.1)Emergency corecooling system
 
valves and lines to
 
and from high
 
pressure coolant
 
injection and reactor
 
core isolation
 
cooling pump
 
turbines (Item Number
 
3.2.1.14)Wall-thinning due toflow-accelerated
 
corrosion Flow Accelerated Corrosion ProgramFlow Accelerated Corrosion ProgramConsistent withGALL which
 
recommends no
 
further evaluation (See Section
 
3.2.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-179 Pumps, valves, piping and fittings in emergency core cooling system (Item Number
 
3.2.1.16)Crack initiation andgrowth due to SCC
 
and IGSCC Water ChemistryProgram; BWR
 
Stress Corrosion
 
Cracking ProgramChemistry ControlProgram; BWR
 
Stress Corrosion
 
Cracking ProgramConsistent withGALL, with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.2.2.1))Closure bolting in high-pressure or
 
high-temperature systems (Item Number
 
3.2.1.18)Loss of material due to general
 
corrosion; crack initiation and growth due to cyclic loading
 
and/or SCC Bolting Integrity Program Bolting Integrity ProgramConsistent withGALL, with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.2.2.1)The staff's review of the BFN component groups followed one of several approaches. One approach, documented in SER Section 3.2.2.1, involves the staff's review of the AMR results for
 
components in the ESF systems that the applicant indicated are consistent with the GALL
 
Report and do not require further evaluation. Another approach, documented in SER
 
Section 3.2.2.2, involves the staff's review of the AMR results for components in the ESF
 
systems that the applicant indicated are consistent with the GALL Report and for which further
 
evaluation is recommended. A third approach, documented in SER Section 3.2.2.3, involves the
 
staff's review of the AMR results for components in the ESF systems that the applicant indicated
 
are not consistent with, or not addressed in, the GALL Report. The staff's review of AMPs that
 
are credited to manage or monitor aging effect s of the ESF systems components is documented in SER Section 3.0.3.3.2.2.1  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation Is Not Recommended Summary of Technical Information in the Application. In LRA Section 3.2.2.1, the applicant identified the materials, environments, and AERMs. The applicant identified the following
 
programs that manage the aging effects re lated to the ESF systems components:
* Bolting Integrity Program
* Buried Piping and Tanks Inspection Program
* Chemistry Control Program
* One-Time Inspection Program
* Open-Cycle Cooling Water System Program
* Selective Leaching of Materials Program
* Systems Monitoring Program
* ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program
* BWR Stress Corrosion Cracking Program
* Flow-Accelerated Corrosion Program Staff Evaluation. In LRA Tables 3.2.2-1 through 3.2.2-7, the applicant provided a summary of AMRs for the ESF systems components, and identified which AMRs it considered to be
 
consistent with the GALL Report.
3-180 For component groups evaluated in the GALL Report which the applicant stated are consistent with the GALL Report, and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the plant-specific components
 
contained in these GALL Report component groups were bounded by the GALL Report
 
evaluation.
The applicant provided a note for each AMR line item. The notes described how the information in the tables aligns with the information in the GALL Report. The staff audited those AMRs with
 
Notes A through E, which indicated the AMR was consistent with the GALL Report.
Note A indicated that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the AMP
 
identified in the GALL Report. The staff audited these line items to verify consistency with the
 
GALL Report and the validity of the AMR for the site-specific conditions.
Note B indicated that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP
 
identified in the GALL Report. The staff audited these line items to verify consistency with the
 
GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been
 
reviewed and accepted by the staff. The staff also determined whether the AMP identified by the
 
applicant was consistent with the AMP identified in the GALL Report and whether the AMR was
 
valid for the site-specific conditions.
Note C indicated that the component for the AMR line item is different from, but consistent with, the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent
 
with the AMP identified by the GALL Report. This note indicates that the applicant was unable to
 
find a listing of some system components in the GALL Report. However, the applicant identified
 
a different component in the GALL Report that had the same material, environment, aging
 
effect, and AMP as the component that was under review. The staff audited these line items to
 
verify consistency with the GALL Report. The staff also determined whether the AMR line item
 
of the different component was applicable to the component under review and whether the AMR
 
was valid for the site-specific conditions.
Note D indicated that the component for the AMR line item is different from, but consistent with, the GALL Report for material, environment, and aging effect. In addition, the AMP takes some
 
exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify
 
consistency with the GALL Report. The staff verified whether the AMR line item of the different
 
component was applicable to the component under review. The staff verified whether the
 
identified exceptions to the GALL AMPs had been reviewed and accepted by the staff. The staff
 
also determined whether the AMP identified by the applicant was consistent with the AMP
 
identified in the GALL Report and whether the AMR was valid for the site-specific conditions.
Note E indicated that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but that a different AMP is credited. The staff audited these line
 
items to verify consistency with the GALL Report. The staff also determined whether the
 
identified AMP would manage the aging effect consistent with the AMP identified by the GALL
 
Report and whether the AMR was valid for the site-specific conditions.
3-181 The staff conducted an audit and review of the information provided in the LRA, as documented in its BFN audit and review report. The staff did not repeat its review of the matters described in
 
the GALL Report. However, the staff did verify that the material presented in the LRA was
 
applicable and that the applicant had identified the appropriate GALL AMRs. The staff's
 
evaluation is discussed below.
For aging management evaluations that the applicant stated are consistent with the GALL Report and for which further evaluation is not recommended, the staff conducted its audit to
 
determine if the applicant's reference to the GALL Report in the LRA is acceptable.
The staff reviewed the LRA to confirm that the applicant (1) provided a brief description of the system, components, materials, and environment; (2) stated that the applicable aging effects
 
have been reviewed and are evaluated in the GALL Report; and (3) identified those aging
 
effects for the ESF system components that are subject to an AMR.
The staff identified that LRA Table 3.2.2.5 is not consistent with the GALL Report Item IVC1.3-c.
The staff asked the applicant to explain this inconsistency. By letter dated October 8, 2004, the
 
applicant submitted its formal response to the staff, stating that the correct AMPs for LRA Table 3.2.2.5 are the Chemistry Control Program and the BWR Stress Corrosion Cracking
 
Program (instead of the One-Time Inspection Program). The staff found this acceptable
 
because it is consistent with the GALL Report.
On the basis of its audit, the staff determined that for AMRs not requiring further evaluation, as identified in LRA Table 3.2.1 (Table 1), the applicant's references to the GALL Report are
 
acceptable and no further staff review is required.
Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating
 
experience and proposals for managing associated aging effects. On the basis of its review, the
 
staff concluded that the AMR results, which the applicant claimed to be consistent with the
 
GALL Report, are consistent with the AMRs in the GALL Report. Therefore, the staff concluded
 
that the applicant had demonstrated that the effects of aging for these components will be
 
adequately managed so that their intended function(s) will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR54.21(a)(3).3.2.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation Is Recommended Summary of Technical Information in the Application. In LRA Section 3.2.2.2, the applicant provided further evaluation of aging management as recommended by the GALL Report for the ESF systems. The applicant provided informati on concerning how it will manage the following aging effects:
* cumulative fatigue damage
* loss of material due to general corrosion
* local loss of material due to pitting and crevice corrosion
* local loss of material due to microbiologically influenced corrosion (MIC)
* changes in properties due to elastomer degradation
* local loss of material due to erosion 3-182
* buildup of deposits due to corrosion
* quality assurance for aging management of NSR components Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report recommends further
 
evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it had
 
adequately addressed the issues that had been further evaluated. In addition, the staff reviewed
 
the applicant's further evaluations against the criteria contained in SRP-LR Section 3.2.2.2.
 
Details of the staff's audit are documented in the staff's audit and review report. The staff's
 
evaluation of the aging effects is discussed in the following sections.
For some line items in LRA Tables 3.2.2.1 through 3.2.2.7 that are identified to be consistent with the GALL Report, the applicant cross-referenced specific line items in LRA Tables 3.1.1
 
and 3.2.1, for which the GALL Report recommends further evaluation. Where the GALL Report
 
recommends further evaluation, the staff reviewed the applicable further evaluations provided in
 
LRA Sections 3.1.2.2 and 3.2.2.2 against the criteria provided in SRP-LR Sections 3.1.2.2 and
 
3.2.2.2, respectively.
The following subsections provide the staff's assessment of the applicant's further evaluations in LRA Section 3.2.2.2 against the criteria provided in SRP-LR Section 3.2.2.2.
The staff's assessment of the applicant's further evaluations in LRA Section 3.1.2.2 is provided in SER Section 3.1.2. Where credited, the assessment also considered applicability to aging
 
management of the ESF systems.
3.2.2.2.1  Cumulative Fatigue Damage
 
Consistent with the SRP-LR, the applicant references LRA Section 4.3.3. Cumulative fatigue damage is a TLAA, and is evaluated in SER Section 4.
3.2.2.2.2  Loss of Material Due to General Corrosion (LRA Section 3.2.2.2.2)
 
The applicant references LRA Table 3.2.1, items 3.2.1.3 and 3.2.1.10, to address loss of material due to general corrosion for ESF components in containment isolation, standby gas
 
treatment, residual heat removal and containment inerting systems and also for RCS
 
components. These Table 1 items reference LRA Section 3.2.2.2.2 for further evaluation. The
 
staff reviewed LRA Section 3.2.2.2.2 against the criteria in SRP-LR Section 3.2.2.2.2.
In LRA Section 3.2.2.2.2, the applicant addressed loss of material due to general corrosion of the portions of ESF systems piping filled with treated water or air/gas, and the external surfaces
 
of carbon steel components.
SRP-LR Section 3.2.2.2.2 states that the management of loss of material due to general corrosion of pumps, valves, piping, and fittings associated with some of the BWR emergency
 
core cooling systems [high pressure coolant injection, reactor core isolation cooling, high
 
pressure core spray, low pressure core spray, low pressure coolant injection (residual heat
 
removal)] and with lines to the suppression chamber and to the drywell and suppression
 
chamber spray system should be further eval uated. The existing AMP relies on monitoring and control of primary water chemistry to mitigate degradation; however, control of primary water 3-183 chemistry does not preclude loss of material due to general corrosion at locations of stagnant flow conditions. Therefore, verification of the effectiveness of the Chemistry Control Program
 
should be performed to ensure that corrosion is not occurring. The GALL Report recommends
 
further evaluation of programs to manage loss of material due to general corrosion to verify the
 
effectiveness of the Chemistry Control Program. A one-time inspection of selected components
 
at susceptible locations is an acceptable method to determine whether an aging effect is not
 
occurring or an aging effect is progressing very slowly such that the component's intended
 
function will be maintained during the period of extended operation. Also, the GALL Report
 
recommends further evaluation on a plant-specific basis to ensure that the aging effect on the
 
external surfaces of BWR carbon steel components is adequately managed.
In the LRA Section 3.2.2.2.2, the applicant stated that loss of material due to general corrosion of the portions of ESF systems filled with tr eated water is managed by the Chemistry Control Program and the One-Time Inspection Program.
The One-Time Inspection Program is used to verify the effectiveness of the Chemistry Cont rol Program for managing the loss of material due to general corrosion. Loss of material due to general corrosion of the air/gas portions of these
 
systems is managed by the One-Time Ins pection Program for internal surfaces.
General corrosion of all external surfaces of carbon steel components is managed by the plant-specific Systems Monitoring Program.
The staff reviewed the BFN procedure (NEDP-20, rev. 3, "Conduct of the Engineering Organization," September 9, 2002) for conducting system
 
monitoring during system walkdowns. The walk down encompasses all or part of the total accessible system, such that the entire system is covered over time. The walkdown is a detailed look at system parameters, material condi tion, operation, configuration, degraded components, outstanding work activities, and design changes. The material condition involves no missing, discolored-indicating-a-potential-leak, or damaged insulation. The staff found that the Systems
 
Monitoring Program would be able to detect any corrosion on the external surfaces of carbon
 
steel components.
On the basis of its review of the Chemistry Control Program, One-Time Inspection Program, and the Systems Monitoring Program, the staff found that the applicant had conducted an
 
acceptable AMR for management of loss of material due to general corrosion, consistent with
 
the recommendations in the GALL Report.
3.2.2.2.3  Local Loss of Material due to Pitting and Crevice Corrosion
 
The applicant references LRA Table 3.2.1, item 3.2.1.5, to address loss of material due to pitting and crevice corrosion for ESF components in containment and containment inerting
 
systems and also for RCS components. The applicant's further evaluation is in LRA
 
Section 3.2.2.2.3. The staff reviewed LRA Section 3.2.2.2.3 against the criteria in SRP-LR
 
Section 3.2.2.2.3.
In the LRA Section 3.2.2.2.3, the applicant addressed local loss of material from pitting and crevice corrosion that could occur in the ESF systems and associated piping filled with treated
 
water or air/gas.
SRP-LR Section 3.2.2.2.3 states that the management of local loss of material due to pitting and crevice corrosion of pumps, valves, piping, and fittings associated with some of the BWR
 
emergency core cooling system piping and fittings [high pressure coolant injection, reactor core 3-184 isolation cooling, high pressure core spray, low pressure core spray, low pressure coolant injection (residual heat removal)] and with lines to the suppression chamber and to the drywell
 
and suppression chamber spray system should be evaluated further. The existing AMP relies on monitoring and control of primary water chemistry to mitigate degradation. However, control of
 
coolant water chemistry does not preclude loss of material due to crevice and pitting corrosion
 
at locations of stagnant flow conditions. Therefore, verification of the effectiveness of the
 
Chemistry Control Program should be performed to ensure that corrosion is not occurring. The
 
GALL Report recommends further evaluation of programs to manage the loss of material due to
 
pitting and crevice corrosion to verify the effe ctiveness of the Chemistry Control Program. A one-time inspection of selected components at susceptible locations is an acceptable method to
 
determine whether an aging effect is not occurring or an aging effect is progressing very slowly
 
so that the component's intended function will be maintained during the period of extended
 
operation.
In the LRA Section 3.2.2.2.3, the applicant stated that loss of material due to pitting and crevice corrosion of the portions of ESF systems filled with treated water is managed by the Chemistry Control Program and the One-Time Inspection Program. The One-Time Inspection Program is used to verify the effectiveness of the Chem istry Control Program for managing the loss of material due to pitting and crevice corrosion. Loss of material due to pitting and crevice
 
corrosion of the air/gas portions of these sy stems is managed by the One-Time Inspection Program for internal surfaces.
On the basis of its review of the Chemistry Control Program and One-Time Inspection Program, the staff found that the applicant had conducted an acceptable AMR for management of loss of
 
material due to pitting and crevice corrosion, consistent with the recommendations in the GALL
 
Report.3.2.2.2.4  Local Loss of Material due to Microbiologically Influenced Corrosion
 
The staff reviewed LRA Section 3.2.2.2.4 against the criteria in SRP-LR Section 3.2.2.2.4.
The applicant references LRA Table 3.2.1, item 3.2.1.6, to address loss of material due to MIC
 
for ESF components in containment and containment inerting systems.
SRP-LR Section 3.2.2.2.4 states that local loss of material due to MIC could occur in containment isolation valves and associated piping in systems that are not addressed in other
 
chapters of the GALL Report. The GALL Report recommends further evaluation to ensure that
 
the aging effect is adequately managed.
LRA Section 3.2.2.2.4 states that the applicant considers MIC to be an aging mechanism for systems in a raw water environment. BFN has no systems containing raw water that penetrate primary containment. Several raw water systems penetrate secondary containment. BFN
 
utilizes the Open-Cycle Cooling Water Program to manage the aging effects that could be
 
caused by MIC in these systems.
On the basis of its review of the Open-Cycle Cooling Water Program, the staff found that the applicant had conducted an acceptable AMR for management of loss of material due to MIC, consistent with the recommendations in the GALL Report.
3-185 3.2.2.2.5  Changes in Properties due to Elastomer Degradation The staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5. In LRA Section 3.2.2.2.5, the applicant described its AMR for change in material properties due to
 
elastomer degradation, for seals in ductwork and filters associated with the standby gas
 
treatment (SGT) system. The applicant stated that the normal operating temperature of the SGT system is less than the defined limits for hardening and loss of strength of installed elastomers.
 
This statement is not consistent with the criteria in SRP-LR Section 3.2.2.2.5.
LRA Table 3.2.2.2, which includes the AMR results for elastomer seals in the SGT system, does not reference LRA Table 1, Item 3.2.1.7. Instead, the applicant identified the AMR for these
 
components to be not consistent with the GALL Report, and concluded that aging management
 
is not required. The staff evaluation of the applicant's AMR results for elastomers in the SGT
 
system was not conducted during the onsite audit.
3.2.2.2.6  Local Loss of Material due to Erosion
 
Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3.2.2.2.7  Buildup of Deposits due to Corrosion
 
The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP-LR Section 3.2.2.2.7. In LRA Section 3.2.2.2.7, the applicant addressed the plugging of components due to general
 
corrosion that could occur in the spray nozzles and flow orifices of the drywell and suppression
 
chamber spray system. The applicant stated that spray nozzles are brass and are not
 
susceptible to general corrosion, and that there are no orifices susceptible to general corrosion
 
that are occasionally wetted in the ESF systems.
The applicant does not reference LRA Table 1, Item 3.2.1.9 in any of the AMR tables for the ESF systems. The applicant concluded that, since the spray nozzles and orifices are not
 
susceptible to general corrosion that may cause plugging, aging management is not required.
 
The staff found the applicant's AMR results to be acceptable, on the basis that the subject
 
components are not susceptible to general corrosion.
3.2.2.2.8  Quality Assurance for Aging Management of Non-Safety-Related Components SER Section 3.0.4 provides the staff's evaluation of the applicant's QA program.
 
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report
 
recommends further evaluation, the staff determined that (1) those attributes or features for
 
which the applicant claimed consistency with the GALL Report were indeed consistent, and (2)
 
the applicant had adequately addressed the issues that were further evaluated. The staff found
 
that the applicant demonstrated that the effects of aging will be adequately managed so that the
 
intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
3-1863.2.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.2.2.1 through 3.2.2.7, the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are not addressed
 
in the GALL Report.
In LRA Tables 3.2.2.1 through 3.2.2.7, the applicant indicated, via Notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a
 
line item in the GALL Report, and provided inform ation concerning how the aging effect will be managed. Specifically, Note F indicated that the material for the AMR line item component is not
 
evaluated in the GALL Report. Note G indicated that the environment for the AMR line item
 
component and material is not evaluated in the GALL Report. Note H indicated that the aging
 
effect for the AMR line item component, materi al, and environment combination is not evaluated in the GALL Report. Note I indicated that the aging effect identified in the GALL Report for the
 
line item component, material, and environment combination is not applicable. Note J indicated
 
that neither the component nor the material and environment combination for the line item is
 
evaluated in the GALL Report.
Staff Evaluation. For component type, material, and environment combinations that are not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine
 
whether the applicant demonstrated that the effects of aging will be adequately managed so
 
that the intended function(s) will be maintained consistent with the CLB during the period of
 
extended operation.
The staff requested the applicant to provide additional information on the issues described in the following general RAIs. These RAIs, the applicant's responses, and the staff's evaluation of
 
the responses are described below.
In RAI 3.2-1, dated November 18, 2004, the staff stated that in LRA Tables 3.2.2.1 through 3.2.2.7, carbon and low-alloy steel bolting in an inside air (external) or outside air (external)
 
environment is not identified with any AERMs. The applicant indicated that this is because BFN
 
does not use high yield strength bolting. Therefore, the staff requested that the applicant
 
discuss the specific material grade used for the bolting in each of the associated systems, and
 
justify the basis for concluding that crack initiation/growth due to SCC is not a concern for the
 
bolting during the period of extended operation.
In its letter dated December 16, 2004, the applicant responded as follows:
The identified aging management program is the Bolting Integrity Program. As noted, a cracking aging effect is not identified because high yield bolting materials (yield strength
 
above 150 ksi) were not identified and plant operating experience does not indicate an
 
adverse history of bolt cracking. Stress corrosion cracking (SCC) of bolted closures and
 
fasteners is a condition of high yield strength bolting material where a fastener that is
 
statically loaded well below its yield strength can experience sudden failure. SCC occurs
 
through the combination of high stress (both applied and residual tensile stresses), a
 
corrosive environment, and a susceptible material. SCC of high yield strength bolted
 
closures in BWRs requires a corrosive environment typically attributed to leakage of
 
pressure boundary joints or exposure to wetted ambient environments (indoor, outdoor, 3-187 buried and submerged) and the use of thread lubricant containing MoS 2 (molybdenum disulfide).
The use of MoS 2 thread lubricant is not allowed by site and engineering procedures.
Therefore, any maintenance on this mechanical equipment would result in the use of
 
non-MoS 2 thread lubricant. Loss of bolting function due to SCC of bolted joints of vendor-supplied mechanical equipment is not expected and no aging management is
 
required for the period of extended operation.
The staff concluded that loss of bolting function due to SCC of bolted joints of vendor-supplied mechanical equipment is not expected and that aging management is not required for these
 
components for the period of extended operation. On the basis of the applicant's response, the
 
staff's concern described in RAI 3.2-1 is resolved.
In RAI 3.2-2, dated November 18, 2004, the staff stated that in LRA Tables 3.2.2.1 through 3.2.2.4, 3.2.2.6, and 3.2.2.7, nickel-alloy bolting in inside air (external) environments were not
 
identified with any AERMs. The applicant invoked industry guidance/experience to support the
 
analysis. Therefore, the staff requested the applicant to provide a detailed discussion of the air
 
environment involved, and to justify the basis for concluding that there are no AERMs under
 
such material/environment combinations. The staff also requested information on the stated
 
industry guidance.
In its letter dated December 16, 2004, the applicant responded as follows:
The nickel-alloy bolting in the Containment Isolation System was evaluated for wear and no applicable wear mechanism was identified for non-RCPB components. Therefore, wear is not an aging mechanism that requires management for the period of extended
 
operation for the Containment Isolation System. Nickel-alloy bolting, similar to stainless
 
steel bolting, is subject to cracking under severe environmental conditions such as high
 
temperature and being buried or submerged (potentially, depending on type of external water). Nickel-alloy bolting in the Containment Isolation System is not subject to this
 
severe environment; therefore, cracking was not identified.
The copper-alloy components exposed to an inside air (external) environment were evaluated individually to determine where condensation or periodic wetting could occur.
 
The identified aging effects were then determined based on the particular copper alloy
 
present and whether condensation or periodic wetting could occur. Based on this
 
evaluation, there were no instances where copper alloys components with > 15% Zn
 
were subjected to an aggressive environment or condensation/periodic wetting.
 
Therefore, no aging effects that require management during the period of extended
 
operation were identified for the copper alloy components in the subject tables. A
 
summary description of the industry guidance (i.e., when industry guidance is referenced
 
was provided in the EPRI Technical Report 1003056, "Non-Class 1 Mechanical
 
Implementation Guideline and Mechanical Tools") for copper alloys.
The applicant response dated December 16, 2004, contains detailed information for copper alloys. On the basis of the applicant's response, the staff's concern described in RAI 3.2-2 is
 
resolved.
3-188 In RAI 3.2-3, dated November 18, 2004, the staff stated that in LRA Table 3.2.2.1, material carbon and low-alloy steel, component type valves in a treated water (internal) environment are
 
not identified with any AERMs. The staff noted that the component, material and environment
 
combination for this component is similar to that identified in the GALL Report, Item V.C.1-a, which recommends a plant-specific AMP to be evaluated for the identified aging effects.
 
Therefore, the staff requested that the applicant explain why the aging effects identified in the
 
GALL Report, such as loss of material due to general, pitting, and crevice corrosion, are not
 
applicable to these components.
In its response, by letter dated December 16, 2004, the applicant stated that the reason for the line entries that indicate no aging effects is an attempt to ensure completeness of GALL Report
 
comparison. For carbon and low-alloy steel valves in a treated water environment, rows 78, 79, and 80 of LRA Table 3.2.2.1 address the applicable aging mechanisms. The applicable GALL
 
Volume 2 line item was determined to be V.C.1-a. which lists five aging effects: general, pitting, crevice, MIC, and biofouling. For a treated water environment, the BFN AMR determined that
 
microbiologically influenced corrosion and biofouling did not require management for the period
 
of extended operation. However, the BFN AMR determined that in addition to the aging
 
mechanisms identified in the GALL Report, galvanic corrosion was also applicable. This was
 
documented in the AMR as:
Galvanic corrosion - Yes, with notes H and 3 General corrosion - Yes, consistent with GALL
 
Pitting corrosion - Yes, consistent with GALL
 
Crevice corrosion - Yes, consistent with GALL
 
Microbiologically influenced corrosion - No, see below
 
Biofouling - No, see below The first aging mechanism is documented in row 78 with notes H and 3. The next three aging mechanisms, which are consistent with the GALL Report, form the basis for row 80 of LRA
 
Table 3.2.2.1. The last two aging mechanisms are documented in row 79 of LRA Table 3.2.2.1
 
with a note 5 was incorrect which should be 4. Note 4, stated that based on system design and
 
operating history, MIC and biofouling were determined to be not applicable to the treated water
 
portions of this system.
The staff found the above applicant's response to have adequately clarified the fact that loss of material due to general, pitting, and crevice (in addition to galvanic) corrosion has indeed been
 
identified in its AMR. Therefore, the staff's concern described in RAI 3.2-3 is resolved.
In RAI 3.2-3, dated November 18, 2004, the staff stated that in LRA Table 3.2.2.3, the applicant did not identify elastomer flexible connectors in an air/gas (internal) environment with any
 
AERMs. The applicant stated that there are no applicable aging effects for this
 
material/environment combination and believes that this is consistent with industry guidance.
 
Therefore, the staff requested additional information to justify the basis for concluding that there
 
are no AERMs under such material/environment combinations, including an insight into the
 
industry guidance.
In its response, by letter dated December 16, 2004, the applicant stated that the issue involved aging effects due to material property changes and cracking of the rubber fabric reinforced (elastomer) flexible connectors upstream and downstream of the gland seal condenser blower 3-189 (gland exhauster) in an air/gas environment. These e ffects are caused by exposure to ultraviolet radiation, oxygen, ozone, heat, and radiation. The applicant stated that the elastomer
 
degradation due to these aging mechanisms are not significant because the ultraviolet radiation
 
and ozone effects to the internal surfaces of the components are negligible. The LRA does
 
identify elastomer degradation due to ultraviolet radiation and ozone for the external surfaces of
 
these components. The applicant further stated that maximum temperature rating for rubber is 130 °F per industry guidance. During normal operation, the temperature of the flexible connectors is significantly less than 130 °F; therefore, degradation from thermal exposure is not identified as an aging
 
mechanism requiring management for the period of extended operation. The applicant further
 
stated that the dose threshold for radiation degradation of rubber is 10 7 rads. The ionizing radiation the flexible connectors will receive is negligible (much less than 10 7 rads); therefore, degradation from ionizing radiation is not identified as an aging mechanism requiring
 
management for the period of extended operation.
The staff found the applicant's basis for not identifying any aging effects for the elastomer flexible connectors to be acceptable. Therefore, the staff's concern described in RAI 3.2-4 is
 
resolved.In RAI 3.2-5, dated November 18, 2004, the staff stated that in LRA Table 3.2.2.5, the applicant stated that aluminum-alloy fittings in a treated water (internal) environment are identified as
 
being susceptible to crack initiation/growth due to SCC and loss of material due to crevice and
 
pitting corrosion. Therefore, the staff requested additional information to explain why loss of
 
material due to general and galvanic corrosion is not identified as a potential AERM during the
 
period of extended operation. The applicant was also requested to explain how the Chemistry
 
Control Program, in association with the One-Time Inspection Program, is used to manage the
 
identified aging effects.
In its response, by letter dated December 16, 2004, the applicant stated that, per industry guidance, aluminum and aluminum-based allo ys in a treated water environment are not susceptible to loss of material due to general corrosion. In addition, the applicant stated that the
 
aluminum fittings in Table 3.2.2.5 are the flanges off the 24-inch diameter condensate supply
 
header within the core spray system. An electrically insulating rubber gasket is used to
 
electrically separate the aluminum flanges from more cathodic materials, such as copper or
 
stainless or carbon steels. Based on that, the staff concurred with the applicant's conclusion that
 
galvanic corrosion is not a concern for this configuration for aluminum fittings in a treated water
 
environment for the core spray system.
The applicant also stated that the main objective of the Chemistry Control Program is to minimize loss of material due to general, crevice, and pitting corrosion and crack initiation and
 
growth caused by SCC. Corrosion and cracking of aluminum alloys in treated water is managed
 
by maintaining oxygen, chlorides, and sulfates within the limits of the Chemistry Control
 
Program. The specific chemistry limits are t he same as the limits used to manage aging of carbon/low-alloy and stainless steel components in a treated water environment. The applicant
 
stated that the use of the Chemistry Control Program is consistent with industry practice as
 
identified in its past precedence review. The staff accepted the Chemistry Control Program for
 
primary systems program and its evaluati on of this program is documented in SERSection 3.0.3.2.2. GALL AMP XI.M32, "One-Time Inspection," is used to verify the Chemistry 3-190 Control Program's effectiveness, as reco mmended by the GALL Report. The staff considered that the applicant had adequately addressed its concerns stated in the RAI; therefore, RAI 3.2-5
 
is resolved.
In RAI 3.2-6, dated November 18, 2004, the staff stated that in LRA Table 3.2.2.5 polymer tubing in an air/gas (internal) or inside air (external) environment is not identified with any
 
AERMs. Therefore, the staff requested the applicant to provide a discussion of the air
 
environment involved, and justify the basis for concluding that there are no AERMs under such
 
material/environment combinations.
In its response, by letter dated December 16, 2004, the applicant stated that polymer tubing in the core spray system is the Tygon (polyvinyl chloride) tube off the closed drain valve
 
downstream of the drain dirt separator (trap) used in the keep fill system (shown on drawing 2-47E814-1). Under normal operating conditions, the internal and external environment is atmospheric air. The applicant stated that unlike metals, thermoplastics do not display corrosion
 
rates. Rather than depending on an oxide layer for protection, they depend on chemical
 
resistance to the environment to which they are exposed. Therefore, acceptability for the use of
 
thermoplastics in an air/gas environment is a design driven criterion. Once the appropriate material is chosen, the system will have no aging effects.The applicant stated that the temperature and radiation damage threshold limits are 200 °F and 2 x 10 7 rads, respectively. Neither of these limits is challenged in the LRA where Tygon is utilized; however, Tygon may be degraded when exposed to air and ultraviolet radiation;
 
therefore, the applicant stated that for the external surface of the Tygon tubing, degradation
 
should have been identified in the LRA by revising the line item to include "Hardening and loss
 
of strength due to polymer degradation (ultraviolet radiation)" as an aging effect and an aging
 
mechanism. The Systems Monitoring Program will be used to manage the aging effect.
Based on the above, the staff considered that the applicant had adequately addressed its concerns; therefore, RAI 3.2-6 is resolved.
3.2.2.3.1  Containment System - Summary of Aging Management Evaluation - Table 3.2.2.1 The staff reviewed LRA Table 3.2.2.1, which summarizes the results of AMR evaluations for the containment system component groups.
In LRA Table 3.2.2.1, the applicant identified no aging effects in containment system component groups made of aluminum alloys exposed to inside/outside air in the ductwork and heat
 
exchangers or carrying air/gas in the ductwork; carbon and low-alloy steel piping/fittings
 
embedded or encased in concrete; copper-alloy piping carrying air/gas; glass (fittings) exposed
 
to air/gas, treated water, or inside air; and nickel-alloy fittings, stainless steel fittings, and
 
zinc-alloy ductwork exposed to air/gas. These environment's conditions are not identified in the
 
GALL Report for these components and materials. On the basis of current industry research
 
and operating experience, dry air on metal will not result in aging that will be of concern during
 
the period of extended operation. The external environments being referred to are typical of ambient air (e.g., under a shelter, indoors, or air-conditioned enclosure or room). Significant
 
corrosion of low-alloy steel requires an electrolytic environment, and a simultaneous presence
 
of oxygen and moisture. Without the presence of an aggressive environment, these components
 
experience insignificant amounts of corrosion, and no aging effects are applicable to this 3-191 component/commodity group. Therefore, the staff concluded that there are no applicable aging effects for these material and environment combinations.
In LRA Table 3.2.2.1, the applicant identified that the loss of material due to general, crevice, pitting and galvanic corrosion in carbon/low-alloy steel, nickel alloys and stainless steel piping
 
and fittings in treated water are managed by t he Chemistry Control Program and One-Time Inspection Program. The Chemistry Control Program relies on monitoring and control of reactor water chemistry based on BWRVIP-79 to prevent loss of material from general, pitting, crevice
 
or galvanic corrosion. However, high concentrations of impurities at crevices and locations of
 
stagnant flow conditions could cause corrosion. Therefore, verification of the effectiveness of
 
the Chemistry Control Program needs to be performed to ensure that corrosion is not occurring.
 
The one-time inspection of selected components at susceptible locations is an acceptable
 
method for ensuring that corrosion is not occurring and that the component's intended function
 
will be maintained during the period of extended operation.
In LRA Table 3.2.2.1, heat exchanger components made of carbon/low-alloy steel and exposed to raw water are susceptible to loss of material due to biofouling, MIC, crevice, galvanic, general, and pitting corrosion; and heat exchanger components made of copper alloys and
 
exposed to raw water are susceptible to fouling due to biological particulate build-up and loss of
 
material due to selective leaching, biofouling, MIC, crevice and pitting corrosion. The applicant
 
credited the Selective Leaching of Materials Program and Open-Cycle Cooling Water System Program to manage these aging effects. The latter AMP, in accordance with the guidelines of
 
GL 89-13, includes managing aging effects by condition monitoring (system and component
 
testing, visual inspections, and NDE testing), and by preventive actions (biocide treatment and
 
filtering to prevent loss of material due to MIC and biofouling and flow blockage and reduction of
 
heat transfer due to biological and particulate fouling). The staff found this acceptable.
Aluminum-alloy heat exchangers carrying air/gas; carbon/low-alloy steel piping/fittings and heat exchangers exposed to air/gas; and copper-alloy components of heat exchangers exposed to
 
air/gas are susceptible to loss of material due to general pitting, crevice corrosion, and fouling
 
due to particulate build-up. In LRA Table 3.2.2.1, the applicant credited the One-Time
 
Inspection Program to manage these aging effects. This aging effect is not in the GALL Report
 
for this component, material, and environment combination. The one-time inspection provides
 
the opportunity to visually inspect the inter nal surfaces of components during preventive and corrective maintenance activities. The staff found the One-Time Inspection Program acceptable
 
for managing the aging effect of loss of material.
In LRA Table 3.2.2.1, piping and fittings made of carbon/low-alloy steel buried in soil are susceptible to loss of material due to MIC, crevice, general, and pitting corrosion. The applicant
 
credited the Buried Piping and Tanks Inspection Program to manage this aging effect. This AMP
 
involves preventive measures to mitigate co rrosion (external coatings and wrappings have been applied in accordance with standard industry practices) and condition monitoring to manage the
 
effects of corrosion. Buried piping is inspected when excavated for any reason, typically for
 
maintenance. The inspections are performed as part of the 10 CFR 50.65, "Maintenance Rule
 
Program." The inspections provide for determination of degradation due to the loss of, or
 
damage to, the protective coatings and wraps used for corrosion control on buried pipe external
 
surfaces. The inspections also include connections and joints for signs of separation, signs of
 
environmental degradation, signs of leakage, and appreciable settlement between piping 3-192 segments. The staff found this inspection program acceptable for managing the aging effect of loss of material.
 
The staff found that the applicant had demonstrated that the effects of aging will be adequately
 
managed so that the intended functions will be maintained consistent with the CLB during the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2.2.3.2  Standby Gas Treatment System
- Summary of Aging Management Evaluation -
Table 3.2.2.2 The staff reviewed LRA Table 3.2.2.2, which summarizes the results of AMR evaluations for the standby gas treatment system component groups.
In LRA Table 3.2.2.2, the applicant identified no aging effects in standby gas treatment system component groups made of aluminum-alloy ductwork, copper-alloy tubing, stainless steel
 
fittings, and zinc-alloy ductwork. All of these components carry air/gas and their external surface
 
is exposed to inside air. These environment conditions are not identified in the GALL Report for
 
these components and materials. On the basis of current industry research and operating
 
experience, dry air on metal will not result in aging that will be of concern during the period of
 
extended operation. The external environments being re ferred to are typical of ambient air (e.g., under a shelter, indoors, or air-conditioned enclosure or room). Significant corrosion of low-alloy
 
steel requires an electrolytic environment, and a simultaneous presence of oxygen and
 
moisture. Without the presence of an aggressive environment, these components experience
 
insignificant amounts of corrosion, and no aging effects are applicable to this
 
component/commodity group. Therefore, the staff concluded that there are no applicable aging
 
effects for these material and environment combinations.
In LRA Table 3.2.2.2, piping and fittings made of carbon/low-alloy steel buried in soil are susceptible to loss of material due to MIC, crevice, general, and pitting corrosion. The applicant
 
credited the Buried Piping and Tanks Inspection Program to manage this aging effect. This AMP
 
involves preventive measures to mitigate co rrosion (external coatings and wrappings have been applied in accordance with standard industry practices) and condition monitoring to manage the
 
effects of corrosion. Buried piping is inspected when excavated for any reason, typically for
 
maintenance. The inspections are performed as part of the 10 CFR 50.65, "Maintenance Rule
 
Program." The inspections provide for determination of degradation due to the loss of, or
 
damage to, the protective coatings and wraps used for corrosion control on buried pipe external
 
surfaces. The inspections also include connections and joints for signs of separation, signs of
 
environmental degradation, signs of leakage, and appreciable settlement between piping
 
segments. The staff found this inspection program acceptable for managing the aging effect of
 
loss of material.
Carbon and low-alloy steel and cast iron/cast iron alloy piping, fittings, and valves exposed to air/gas are susceptible to loss of material due to general corrosion. In LRA Table 3.2.2.2, the
 
applicant credited the One-Time Inspection Program to manage loss of material in these
 
components. This aging effect is not in the GALL Report for this component, material, and
 
environment combination. The one-time inspection pr ovides the opportunity to visually inspect the internal surfaces of components during preventive and corrective maintenance activities.
 
The staff found the One-Time Inspection Program acceptable for managing the aging effect of
 
loss of material.
3-193 Carbon and low-alloy steel and cast iron/cast iron alloy piping, fittings, and valves external surfaces exposed to inside air are managed by the Systems Monitoring Program against any loss of material due to general corrosion. The system walkdown encompasses all or part of the
 
total accessible system, such that the entire sy stem is covered over time. The walkdown is a detailed look at system parameters, material condition, operation, configuration, degraded
 
components, outstanding work activities, and design changes. The material condition involves
 
no missing, discolored-indicating-a-potential-leak, or damaged insulation. The staff found that
 
the Systems Monitoring Program would be able to detect any corrosion on the external surfaces of these components.
The staff found that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2.2.3.3  High Pressure Coolant Injection Sy stem - Summary of Aging Management Evaluation
- Table 3.2.2.3 The staff reviewed LRA Table 3.2.2.3, which summarizes the results of AMR evaluations for the high pressure coolant injection (HPCI) system component groups.
In LRA Table 3.2.2.3, the applicant identified no aging effects in HPCI system component groups made (1) out of carbon and low-alloy steel piping and fittings exposed to inside air (external surface) and carrying lube oil, cast iron alloy pumps and valves carrying lube oil; (2)
 
copper-alloy tubing/fittings carrying air/gas and lube oil; (3) glass (fittings) exposed to air/gas
 
and lube oil; and (4) nickel-alloy flexible connectors and stainless steel fittings exposed to inside
 
air (external). These environment conditions are not identified in the GALL Report for these
 
components and materials. On the basis of current industry research and operating experience, dry air on metal will not result in aging that will be of concern during the period of extended
 
operation. The external environments being referred to are typical of ambient air (e.g., under a shelter, indoors, or air-conditioned enclosure or room). Significant corrosion requires an
 
electrolytic environment, and a simultaneous presence of oxygen and moisture. Without the
 
presence of an aggressive environment, these components experience insignificant amounts of corrosion, and no aging effects are applicable to this component/commodity group. Therefore, the staff concluded that there are no applicable aging effects for these material and environment
 
combinations.
In LRA Table 3.2.2.3, the applicant identified that the loss of material due to general, crevice, pitting and galvanic corrosion in carbon/low-alloy steel piping, fittings, and various components, cast iron and cast iron alloy pumps, copper-alloy condensers and heat exchangers, nickel-alloy
 
flexible connectors, and stainless steel piping, fittings, tubing, and valves in treated water are
 
managed by the Chemistry Control Program and One-Time Inspection Program. The Chemistry Control Program relies on monitoring and control of reactor water chemistry based on
 
BWRVIP-79 to prevent loss of material from general, pitting, crevice or galvanic corrosion.
However, high concentrations of impurities at crevices and locations of stagnant flow conditions
 
could cause corrosion. Therefore, verification of the effectiveness of the Chemistry Control
 
Program needs to be performed to ensure that corrosion is not occurring. The one-time
 
inspection of selected components at susceptible locations is an acceptable method for
 
ensuring that corrosion is not occurring and the component's intended function will be
 
maintained during the period of extended operation.
3-194 In components made from cast iron and cast iron alloys and copper alloy, selective leaching takes place when these components are exposed to corrosion-inhibited treated water, oxygenated and de-oxygenated treated water. In LRA Table 3.2.2.3, the applicant identified
 
Selective Leaching of Materials Program to manage loss of material due to selective leaching in
 
cast iron pumps and copper-alloy condensers exposed to treated water. The applicant's
 
selective leaching program relies on vis ual inspections and hardness measurements on selected components susceptible to selective leaching. On the basis of industry operating
 
experience with this material and environment, the staff found this acceptable.
Cast iron/cast iron alloy fittings and carbon and low-alloy steel external surfaces exposed to inside air are managed by the Systems Monitori ng Program against any loss of material due to general corrosion. Elastomer flexible connections exposed to inside air are subject to elastomer
 
degradation due to ultraviolet radiation, whic h is also managed by the Systems Monitoring Program. The system walkdown encompasses all or part of the total accessible system, such that the entire system is covered over time. The walkdown is a detailed look at system
 
parameters, material condition, operation, configuration, degraded components, outstanding
 
work activities, and design changes. The material condition involves no missing, discolored-indicating-a-potential-leak, or damaged insulation. The staff found that the Systems
 
Monitoring Program would be able to detect any corrosion on the external surfaces of these
 
components.
The staff found that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2.2.3.4  Residual Heat Removal System
- Summary of Aging Management Evaluation -
Table 3.2.2.4 The staff reviewed LRA Table 3.2.2.4, which summarizes the results of AMR evaluations for the residual heat removal (RHR) system component groups.
In LRA Table 3.2.2.4, the applicant identified no aging effects in RHR system component groups made of aluminum exposed to inside air (external), carbon and low-alloy steel piping/fittings
 
exposed to inside air (external), and copper-alloy and stainless steel fittings carrying air/gas.
 
These environment conditions are not identified in the GALL Report for these components and
 
materials. On the basis of current industry research and operating experience, dry air on metal
 
will not result in aging that will be of concern during the period of extended operation. The
 
external environments being referred to are typica l of ambient air (e.g., under a shelter, indoors, or air-conditioned enclosure or room). Significant corrosion requires an electrolytic environment, and a simultaneous presence of oxygen and moisture. Without the presence of an aggressive
 
environment, these components experience insi gnificant amounts of corrosion, and no aging effects are applicable to this component/commodity group. Therefore, the staff concluded that
 
there are no applicable aging effects for these material and environment combinations.
In LRA Table 3.2.2.4, the applicant identified that the loss of material due to general, crevice, pitting and galvanic corrosion in carbon/low-alloy steel heat exchangers, piping, fittings, and
 
other components, cast iron alloy pumps, copper-alloy, and aluminum alloy fitting, and stainless
 
steel piping, fittings, and other components in treated water are managed by the Chemistry
 
Control Program and One-Time Inspection Progr am. The Chemistry Control Program relies on 3-195 monitoring and control of reactor water chemistry based on BWRVIP-79 to prevent loss of material from general, pitting, crevice or galvanic corrosion. However, high concentrations of
 
impurities at crevices and locations of stagnant flow conditions could cause corrosion.
 
Therefore, verification of the effectiveness of the Chemistry Control Program needs to be
 
performed to ensure that corrosion is not occurring. The one-time inspection of selected
 
components at susceptible locations is an acceptable method for ensuring that corrosion is not
 
occurring and the component's intended function will be maintained during the period of
 
extended operation.
In components made from cast iron and copper allo y, selective leaching takes place when these components are exposed to raw water, corrosion-inhibited treated water, oxygenated and
 
de-oxygenated treated water, or are buried underground. In LRA Table 3.2.2.4, the applicant
 
identified the Selective Leaching of Materials Program to manage loss of material due to
 
selective leaching in cast iron heat exchangers and pumps and copper-alloy fittings exposed to
 
raw water or treated water. The applicant's selective leaching program relies on visual
 
inspections and hardness measurements on sele cted components susceptible to selective leaching. On the basis of industry operating experience with this material and environment, the
 
staff found this acceptable.
Carbon and low-alloy steel components and cast iron/cast iron alloy heat exchangers and pumps' external surfaces exposed to insi de air are managed by the Systems Monitoring Program against any loss of material due to general corrosion. The system walkdown
 
encompasses all or part of the total accessible sy stem such that the entire system is covered over time. The walkdown is a detailed look at system parameters, material condition, operation, configuration, degraded components, outstanding work activities, and design changes. The
 
material condition involves no missing, discolored-indicating-a-potential-leak, or damaged
 
insulation. The staff found that the Systems Monitoring Program would be able to detect any
 
corrosion on the external surfaces of these components.
In LRA Table 3.2.2.4, heat exchanger components made of carbon/low-alloy steel, cast iron alloys and stainless steel exposed to raw water are susceptible to loss of material due to
 
biofouling, MIC, crevice, galvanic, general, and pitting corrosion as well as fouling product
 
buildup due to biological. The applicant credited the Open-Cycle Cooling Water System
 
Program to manage this aging effect. This AMP, in accordance with the guidelines of GL 89-13, includes managing aging effects by condition monitoring (system and component testing, visual
 
inspections, and NDE testing), and by preventive actions (biocide treatment and filtering to
 
prevent loss of material due to MIC, biofouling, flow blockage and reduction of heat transfer due
 
to biological and particulate fouling). The staff found this acceptable.
Carbon and low-alloy steel and cast iron/cast iron alloy fittings exposed to air/gas are susceptible to loss of material due to general corrosion. In LRA Table 3.2.2.4, the applicant
 
credited the One-Time Inspection Program to manage loss of material in these components.
 
This aging effect is not in the GALL Report for this component, material, and environment
 
combination. The one-time inspection provides the opportunity to visually inspect the internal
 
surfaces of components during preventive and corrective maintenance activities. The staff found
 
the One-Time Inspection Program acceptable for managing the aging effect of loss of material.
3-196 The staff found that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2.2.3.5  Core Spray System - Summary of Aging Management Evaluation - Table 3.2.2.5
 
The staff reviewed LRA Table 3.2.2.5, which summarizes the results of AMR evaluations for the core spray system component groups.
In LRA Table 3.2.2.5, the applicant identified no aging effects in core spray system component groups made of aluminum exposed to inside air (external); carbon and low-alloy steel
 
piping/fittings exposed to inside air (external); and stainless steel fittings carrying air/gas or
 
exposed to inside air. These environment conditions are not identified in the GALL Report for
 
these components and materials. On the basis of current industry research and operating
 
experience, dry air on metal will not result in aging that will be of concern during the period of
 
extended operation. The external environments being re ferred to are typical of ambient air (e.g., under a shelter, indoors, or air-conditioned enclosure or room). Significant corrosion requires an
 
electrolytic environment, and a simultaneous presence of oxygen and moisture. Without the
 
presence of an aggressive environment, these components experience insignificant amounts of corrosion, and no aging effects are applicable to this component/commodity group. Therefore, the staff concluded that there are no applicable aging effects for these material and environment
 
combinations.
In LRA Table 3.2.2.5, the applicant identified that the loss of material due to general, crevice, pitting and galvanic corrosion in carbon/low-alloy steel heat exchangers, piping, fittings, and
 
various other components, cast iron alloy pumps, and stainless steel piping, fittings, and valves
 
in treated water are managed by the Chemistr y Control Program and One-Time Inspection Program. The Chemistry Control Program relies on monitoring and control of reactor water
 
chemistry based on BWRVIP-79 to prevent loss of material from general, pitting, crevice or
 
galvanic corrosion. However, high concentrations of impurities at crevices and locations of
 
stagnant flow conditions could cause corrosion; therefore, verification of the effectiveness of the
 
Chemistry Control Program needs to be performed to ensure that corrosion is not occurring.
 
The one-time inspection of selected components at susceptible locations is an acceptable
 
method for ensuring that corrosion is not occurring and the component's intended function will
 
be maintained during the period of extended operation.
In components made from cast iron alloys, selective leaching takes place when these components are exposed to corrosion-inhibited treated water, oxygenated and de-oxygenated
 
treated water. In LRA Table 3.2.2.5, the applicant identified Selective Leaching of Materials
 
Program to manage loss of material due to selective leaching in cast iron heat exchangers and
 
pumps exposed to treated water. The applicant's selective leaching program relies on visual
 
inspections and hardness measurements on sele cted components susceptible to selective leaching. On the basis of industry operating experience with this material and environment, the
 
staff found this acceptable.
Carbon/low-alloy steel components and cast iron/cast iron alloy pumps external surfaces exposed to inside air are managed by the Syst ems Monitoring Program against any loss of material due to general corrosion. The system walkdown encompasses all or part of the total
 
accessible system, such that the entire system is covered over time. The walkdown is a detailed 3-197 look at system parameters, material condi tion, operation, configuration, degraded components, outstanding work activities, and design changes. The material condition involves no missing, discolored-indicating-a-potential-leak, or damaged insulation. The staff found that the Systems
 
Monitoring Program would be able to detect any corrosion on the external surfaces of these
 
components.
Carbon/low-alloy steel and cast iron/cast iron alloy components exposed to air/gas are susceptible to loss of material due to general corrosion. In LRA Table 3.2.2.5, the applicant
 
credited the One-Time Inspection Program to manage loss of material in these components.
 
This aging effect is not in the GALL Report for this component, material, and environment
 
combination. The one-time inspection provides the opportunity to visually inspect the internal
 
surfaces of components during preventive and corrective maintenance activities. The staff found
 
the One-Time Inspection Program acceptable for managing the aging effect of loss of material.
The staff found that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2.2.3.6  Containment Inerting System
- Summary of Aging Management Evaluation -
Table 3.2.2.6 The staff reviewed LRA Table 3.2.2.6, which summarizes the results of AMR evaluations for the containment inerting system component groups.
In LRA Table 3.2.2.6, the applicant identified no aging effects in containment inerting system component groups made of aluminum, carbon and low-alloy steel, copper alloys, nickel alloys, and stainless steel carrying air/gas or exposed to inside air. These environment conditions are
 
not identified in the GALL Report for these components and materials. On the basis of current
 
industry research and operating experience, dry air on metal will not result in aging that will be
 
of concern during the period of extended operat ion. The external environments being referred to are typical of ambient air (e.g., under a shelter, indoors, or air-conditioned enclosure or room).
 
Significant corrosion requires an electrolytic environment, and a simultaneous presence of
 
oxygen and moisture. Without the presence of an aggressive environment, these components
 
experience insignificant amounts of corrosion, and no aging effects are applicable to this
 
component/commodity group; therefore, the staff concluded that there are no applicable aging
 
effects for these material and environment combinations.
Carbon/low-alloy steel and cast iron/cast iron alloy components exposed to air/gas are susceptible to loss of material due to general corrosion. In LRA Table 3.2.2.6, the applicant
 
credited the One-Time Inspection Program to manage loss of material in these components.
 
This aging effect is not in the GALL Repot for this component, material, and environment
 
combination. The one-time inspection provides the opportunity to visually inspect the internal
 
surfaces of components during preventive and corrective maintenance activities. The staff found
 
the One-Time Inspection Program acceptable for managing the aging effect of loss of material.
The staff found that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
3-198 3.2.2.3.7  Containment Atmosphere Dilu tion System - Summary of Aging Management Evaluation - Table 3.2.2.7 The staff reviewed LRA Table 3.2.2.7, which summarizes the results of AMR evaluations for the containment atmosphere dilution system component groups.
In LRA Table 3.2.2.7, the applicant identified no aging effects in containment inerting system component groups made of aluminum, cast iron alloys, copper alloys, and stainless steel
 
carrying air/gas or exposed to inside air. These environment conditions are not identified in the
 
GALL Report for these components and materials. On the basis of current industry research
 
and operating experience, dry air on metal will not result in aging that will be of concern during
 
the period of extended operation. The external environments being referred to are typical of ambient air (e.g., under a shelter, indoors, or air-conditioned enclosure or room). Significant
 
corrosion requires an electrolytic environment, and a simultaneous presence of oxygen and
 
moisture. Without the presence of an aggressive environment, these components experience
 
insignificant amounts of corrosion, and no aging effects are applicable to this
 
component/commodity group; therefore, the staff concluded that there are no applicable aging
 
effects for these material and environment combinations.
Carbon/low-alloy steel and cast iron alloy components exposed to air/gas are susceptible to loss of material due to general corrosion. In LRA Table 3.2.2.7, the applicant credited the
 
One-Time Inspection Program to manage loss of material in these components. This aging
 
effect is not in the GALL Report for this component, material, and environment combination. The
 
one-time inspection provides the opportunity to visually inspect the internal surfaces of
 
components during preventive and corrective maintenance activities. The staff found the
 
One-Time Inspection Program acceptable for managing the aging effect of loss of material.
Carbon/low-alloy steel and cast iron alloy components' external surfaces exposed to inside air are managed by the Systems Monitoring Program against any loss of material due to general corrosion. The system walkdown encompasses all or part of the total accessible system such that the entire system is covered over time. The walkdown is a detailed look at system
 
parameters, material condition, operation, configuration, degraded components, outstanding
 
work activities, and design changes. The material condition involves no missing, discolored-indicating-a-potential-leak, or damaged insulation. The staff found that the Systems
 
Monitoring Program would be able to detect any corrosion on the external surfaces of these
 
components.
In LRA Table 3.2.2.7, piping and fittings made of stainless steel buried in soil are susceptible to loss of material due to MIC, crevice, general, and pitting corrosion as well as cracking due to
 
SCC. The applicant credited the Buried Piping and Tanks Inspection Program to manage this
 
aging effect. During the GALL consistency audit the staff requested the applicant to describe
 
how this AMP would detect cracking in buried piping, if this is an applicable aging effect. By
 
letter dated October 8, 2004, the applicant submitted its formal response to the staff's audit question, stating that, in Table 3.2.2.7, line items 12 and 22 identify cracking for buried stainless steel piping and fittings and should be deleted. This line's temperature is less than 140 °F and, therefore, is not subject to stress corrosion cracking. This is the only place in the LRA where the
 
buried tank and piping inspection program was credited for detecting cracking. Therefore, the
 
buried tank and piping inspection program does not detect cracking. The staff found the above
 
explanation acceptable.
3-199 The buried tank and piping inspection AMP involves preventive measures to mitigate corrosion (external coatings and wrappings applied in accordance with standard industry practices) and
 
condition monitoring to manage the effects of corrosion. Buried piping is inspected when
 
excavated for any reason, typically for main tenance. The inspections are performed as part of the 10 CFR 50.65, "Maintenance Rule Program." The inspections provide for determination of
 
degradation due to the loss of, or damage to, the protective coatings and wraps used for
 
corrosion control on buried pipe external surfaces. The inspections also include connections
 
and joints for signs of separation, environmental degradation, leakage, and for appreciable
 
settlement between piping segments. The staff found this inspection program acceptable for
 
managing the aging effect of loss of material.
 
The staff found that the applicant had demonstrated that the effects of aging will be adequately
 
managed so that the intended functions will be maintained consistent with the CLB during the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
Conclusion. On the basis of its review, the staff found that the applicant had appropriately evaluated AMR results involving MEAP combinations that are not evaluated in the GALL
 
Report. The staff found that the applicant demonstrated that the effects of aging will be
 
adequately managed so that the intended functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
====3.2.3 Conclusion====
The staff concluded that the applicant had provided sufficient information to demonstrate that the effects of aging for the of the ESF systems components that are within the scope of license
 
renewal and subject to an AMR will be adequately managed so that the intended function(s) will
 
be maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the applicable UFSAR supplement program
 
summaries and concluded that they adequately describe the AMPs credited for managing aging
 
of the ESF systems, as required by 10 CFR 54.21(d).
3-2003.3  Aging Management of Auxiliary Systems This section of the SER documents the staff's review of the applicant's AMR results for the auxiliary systems components and component groups associated with the following systems:
* auxiliary boiler
* fuel oil
* residual heat removal service water
* raw cooling water
* raw service water
* high pressure fire protection
* potable water
* ventilation
* heating, ventilation, and air conditioning (HVAC)
* control air
* service air
* CO 2
* station drainage
* sampling and water quality
* building heat
* raw water chemical treatment
* demineralizer backwash air
* standby liquid control
* off-gas
* emergency equipment cooling water
* reactor water cleanup
* reactor building closed cooling water
* reactor core isolation cooling
* auxiliary decay heat removal
* radioactive waste treatment
* fuel pool cooling and cleanup
* fuel handling and storage
* diesel generator
* control rod drive (CRD)
* diesel generator starting air
* radiation monitoring
* neutron monitoring
* traversing in-core probe
* cranes3.3.1  Summary of Technical Information in the Application In LRA Section 3.3, the applicant provided AMR results for components. In LRA Table 3.3.1,"Summary of Aging Management Evaluations for Auxiliary Systems Evaluated in Chapter VII of NUREG-1801," the applicant provided a summary comparison of its AMRs with the AMRs
 
evaluated in the GALL Report for the auxilia ry systems components and component groups.
3-201 The applicant's AMRs incorporated applicable operating experience in the determination of AERMs. These reviews included evaluation of plant-specific and industry operating experience.
 
The plant-specific evaluation included reviews of condition reports and discussions with
 
appropriate site personnel to identify AERMs. The applicant's review of industry operating
 
experience included a review of the GALL Report and operating experience issues identified
 
since the issuance of the GALL Report.
 
====3.3.2 Staff====
Evaluation The staff reviewed LRA Section 3.3 to determine if the applicant had provided sufficient information to demonstrate that the effects of aging for the auxiliary systems components that are within the scope of license renewal and subject to an AMR will be adequately managed so
 
that the intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
The staff performed an onsite audit, during the weeks of June 21 and July 26, 2004, of AMRs to confirm the applicant's claim that certain identified AMRs are consistent with the GALL Report.
 
The staff did not repeat its review of the matters described in the GALL Report; however, the
 
staff did verify that the material presented in the LRA was applicable and that the applicant had
 
identified the appropriate GALL AMRs. The staff's evaluations of the AMPs are documented in
 
SER Section 3.0.3. Detail of the staff's audit evaluation are documented in the audit and review
 
report and are summarized in SER Section 3.3.2.1.
In the onsite audit, the staff also included those selected AMRs that are consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the
 
applicant's further evaluations are consistent with the acceptance criteria in SRP-LR
 
Section 3.3.2.2. The staff's audit evaluations are documented in the audit and review report and
 
are summarized in SER Section 3.3.2.2.
During the staff's onsite audit, the staff also conducted a technical review of the remaining AMRs that are not consistent with, or not addressed in, the GALL Report. The audit and
 
technical review included evaluating whether all plausible aging effects had been identified and
 
whether the aging effects listed were appropriate for the combination of materials and
 
environments specified. The staff's audit evaluations are documented in the audit and review
 
report and are summarized in SER Section 3.3.2.3. The staff's evaluation of its technical review
 
is also documented in SER Section 3.3.2.3.
Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or
 
monitoring aging for the aux iliary systems components.
Table 3.3-1 below provides a summary of the staff's evaluation of components, aging effects/mechanisms, and AMPs listed in LRA Section 3.3, that are addressed in the GALL
 
Report.
3-202Table 3.3-1  Staff Evaluation for Auxiliary Systems Components in the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation Components in spent fuel pool
 
cooling and cleanup (Item Number
 
3.3.1.1)Loss of material due to general, pitting, and crevice
 
corrosionChemistry ControlProgram; One-Time
 
Inspection ProgramChemistry ControlProgram; One-Time
 
Inspection ProgramConsistent withGALL, which
 
recommends further
 
evaluation (See
 
Section 3.3.2.2.1)
Linings in spent fuel pool cooling and cleanup system;
 
seals and collars in ventilation systems (Item Number
 
3.3.1.2)Hardening, cracking and loss of strength
 
due to elastomer
 
degradation; loss of material due to wearPlant-specificSystems Monitoring Program (See Section 3.3.2.2.2)
Components in load handling, chemical
 
and volume control system (PWR), and reactor water
 
cleanup and shutdown cooling systems (older
 
BWR)
(Item Number
 
3.3.1.3)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAAThis TLAA is evaluated in
 
Section 4.7, Other
 
Plant-Specific Analyses, and in
 
Section 4.3, Metal FatigueBFN does not have a chemical and
 
volume control system or a shutdown cooling system Heat exchangers inreactor water cleanup system (BWR); high
 
pressure pumps in
 
chemical and
 
volume control system (PWR)
(Item Number
 
3.3.1.4)Crack initiation andgrowth due to SCC
 
or crackingPlant-specificChemistry ControlProgram; One-Time
 
Inspection Program (See Section 3.3.2.2.4)
Components inventilation systems, diesel fuel oil system, and emergency diesel generator systems;
 
external surfaces of
 
carbon steel
 
components (Item Number
 
3.3.1.5)Loss of material due to general, pitting, and crevice
 
corrosion; MICPlant-specificChemistry ControlProgram; One-Time
 
Inspection Program (See Section 3.3.2.2.4)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-203 Components in reactor coolant
 
pump oil collect system of fire
 
protection (Item Number
 
3.3.1.6)Loss of material due to galvanic, general, pitting, and crevice
 
corrosionOne-Time InspectionN/ANot applicableBFN does not have
 
an oil collection system for its
 
reactor recirculation
 
pumps Diesel fuel oil tanks in diesel fuel oil system and emergency diesel generator system (Item Number
 
3.3.1.7)Loss of material due to general, pitting, and crevice
 
corrosion, MIC, and
 
biofoulingFuel Oil ChemistryProgram; One-Time
 
Inspection ProgramFuel Oil ChemistryProgram; One-Time
 
Inspection ProgramConsistent withGALL, which
 
recommends further
 
evaluation (See
 
Section 3.3.2.2.7)
Piping, pump casing, and valve body and bonnets in shutdown cooling system (older BWR)
(Item Number
 
3.3.1.8)Loss of material due to pitting and
 
crevice corrosionChemistry ControlProgram; One-Time
 
Inspection ProgramChemistry ControlProgram; One-Time
 
Inspection Program Not applicableBFN is not an older BWR with a shutdown cooling system The shutdown cooling system is performed by the RHR system (See
 
Section 3.3.2.3.3)
Neutron absorbing sheets in spent fuel
 
storage racks (Item Number
 
3.3.1.10)Reduction of neutron absorbing capacity and loss of
 
material due to
 
general corrosion (Boral, boron steel)Plant-specificChemistry Control Program (See Section 3.3.2.2.10)New fuel rackassembly (Item
 
Number 3.3.1.11)
Loss of material due to general, pitting, and crevice
 
corrosion Structures Monitoring Program Structures Monitoring ProgramConsistent withGALL, which
 
recommend no
 
further evaluation (See Section
 
3.3.2.1)Neutron absorbing sheets in spent fuel
 
storage racks (Item Number
 
3.3.1.12)Reduction of neutron absorbing capacity due to
 
Boraflex degradation Boraflex Monitoring ProgramN/ANot applicableBFN uses Boral as
 
the spent fuel
 
storage rack
 
neutron absorber Spent fuel storage racks and valves in
 
spent fuel pool
 
cooling and cleanup (Item Number
 
3.3.1.13)Crack initiation andgrowth due to stress
 
corrosion crackingChemistry Control ProgramChemistry Control ProgramConsistent withGALL, which
 
recommends no
 
further evaluation (See Section
 
3.3.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-204 Components in or serviced by closed-cycle cooling water system (Item Number
 
3.3.1.15)Loss of material due to general, pitting, and crevice
 
corrosion; MICClosed-CycleCooling Water SystemClosed-CycleCooling Water SystemConsistent withGALL, which
 
recommends no
 
further evaluation (See Section
 
3.3.2.1)Cranes includingbridge and trolleys and rail system in
 
load handling system (Item Number
 
3.3.1.16)Loss of material due to general corrosion and wear Overhead Heavy Load and Light
 
Load Handling Systems Overhead Heavy Load and Light
 
Load Handling SystemsConsistent withGALL, which
 
recommends no
 
further evaluation (See Section
 
3.3.2.1)Components in or serviced by open-cycle cooling water systems (Item Number
 
3.3.1.17)Loss of material due to general, pitting, crevice, and
 
galvanic corrosion, MIC, and biofouling;
 
buildup of deposit
 
due to biofoulingOpen-Cycle CoolingWater SystemOpen-Cycle CoolingWater SystemConsistent withGALL, which
 
recommends no
 
further evaluation (See Section
 
3.3.2.1)Buried piping and fittings (Item Number
 
3.3.1.18)Loss of material due to general, pitting, and crevice
 
corrosion; MIC Buried Piping andTanks Surveillance
 
Program; Buried Piping and Tanks
 
Inspection Program Buried Piping andTanks Inspection
 
Program (See Section 3.3.2.2.11)
Components in compressed air system (Item Number
 
3.3.1.19)Loss of material due to general and
 
pitting corrosion Compressed Air Monitoring Program Compressed Air Monitoring ProgramConsistent withGALL, which
 
recommends no
 
further evaluation (See Section
 
3.3.2.1)Components (doors and barrier
 
penetration seals)
 
and concrete
 
structures in fire
 
protections (Item Number
 
3.3.1.20)Loss of material dueto wear; hardening
 
and shrinkage due to weatheringFire Protection ProgramFire Protection ProgramConsistent withGALL, with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.3.2.1)Components inwater-based fire
 
protection (Item Number
 
3.3.1.21)Loss of material due to general, pitting, crevice, and
 
galvanic corrosion, MIC, and biofoulingFire Water SystemFire Water SystemConsistent withGALL, which
 
recommends no
 
further evalation (See Section
 
3.3.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-205 Components indiesel fire system (Item Number
 
3.3.1.22)Loss of material due to galvanic, general, pitting, and crevice
 
corrosionFire ProtectionProgram; Fuel Oil Chemistry ProgramFire ProtectionProgram; Fuel Oil Chemistry ProgramConsistent withGALL, with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.3.2.1)Tanks in diesel fueloil system (Item Number
 
3.3.1.23)Loss of material due to general, pitting, and crevice
 
corrosion Above GroundCarbon Steel Tanks
 
Program Above GroundCarbon Steel Tanks
 
ProgramConsistent withGALL, with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.3.2.1)Closure bolting (Item Number
 
3.3.1.24)Loss of material due to general
 
corrosion; crack initiation and growth due to cyclic loading
 
and SCC Bolting Integrity Program Bolting Integrity ProgramConsistent withGALL, with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.3.2.1)Components incontact with sodium
 
pentaborate solution in standby liquid control system (BWR)
(Item Number
 
3.3.1.25)Crack initiation andgrowth due to SCCChemistry Control ProgramChemistry Control ProgramConsistent withGALL, with exceptions, which
 
recommend no
 
further evaluation (See Section
 
3.3.2.1)Components inreactor water cleanup system (Item Number
 
3.3.1.26)Crack initiation andgrowth due to SCC
 
and IGSCC Reactor WaterCleanup System
 
Inspection Program BWR Reactor WaterCleanup System
 
ProgramThe NUREG-1801 XI.M25 Reactor Water Cleanup system AMP
 
provides criteria for which inspections
 
are not recommended.
Since BFN meets
 
these criteria, inspections will not
 
be conducted (See
 
Section 3.0.3.2.15)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-206 Components inshutdown cooling system (older BWR)
(Item Number
 
3.3.1.27)Crack initiation andgrowth due to SCC BWR Stress Corrosion Cracking
 
Program; Chemistry
 
Control ProgramN/ANot applicableBFN is not an older BWR with a shutdown cooling system. The shutdown cooling
 
function is performed by the RHR system (See
 
Section 3.3.2.3.3)
Components inshutdown cooling system (older BWR)
(Item Number
 
3.3.1.28)Loss of material due to pitting and
 
crevice corrosion, and MICClosed-CycleCooling Water SystemN/ANot applicableBFN is not an older BWR with a shutdown cooling system. The shutdown cooling
 
function is performed by the RHR system (See
 
Section 3.3.2.3.3)
Components (aluminum, bronze, brass, cast iron, cast steel) in open-cycle and closed-cycle cooling water systems, and
 
ultimate heat sink Loss of material due to selective leaching Selective Leaching of Materials
 
Program Selective Leaching of Materials
 
ProgramConsistent withGALL, which
 
recommend no
 
further evaluation (See Section
 
3.3.2.1)Fire barriers, walls, ceilings, and floors
 
in fire protection Concrete cracking and spalling due to freeze-thaw, aggressive chemical
 
attack, and reaction with aggregates;
 
loss of material due
 
to corrosion of
 
embedded steelFire ProtectionSystem; Structures Monitoring SystemFire ProtectionSystem; Structures Monitoring SystemConsistent withGALL, with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.3.2.1)The staff's review of the BFN component groups followed one of several approaches. One approach, documented in SER Section 3.3.2.1, involves the staff's review of the AMR results for
 
components in the auxiliary systems that the applic ant indicated are consistent with the GALL Report and do not require further evaluation. Another approach, documented in SER
 
Section 3.3.2.2, involves the staff's review of the AMR results for components in the auxiliary
 
systems that the applicant indicated are consistent with the GALL Report and for which further
 
evaluation is recommended. A third approach, documented in SER Section 3.3.2.3, involves the
 
staff's review of the AMR results for com ponents in the auxiliary systems that the applicant indicated are not consistent with, or not addressed in, the GALL Report. The staff's review of 3-207 AMPs that are credited to manage or monitor aging effects of the auxiliary systems components is documented in SER Section 3.0.3.3.3.2.1  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Not Recommended Summary of Technical Information in the Application. In LRA Section 3.3.2.1, the applicant identified the materials, environments, and aging effects requiring management. The applicant
 
identified the following programs that manage the aging effects related to the auxiliary systems components:
* Bolting Integrity Program (B.2.1.16)
* One-Time Inspection Program (B.2.1.29)
* Selective Leaching of Materials Program (B.2.1.30)
* Systems Monitoring Program (B.2.1.39)
* Buried Piping and Tanks Inspection Program (B.2.1.25)
* Fuel Oil Chemistry Program (B.2.1.27)
* Chemistry Control Program (B.2.1.5)
* Open-Cycle Cooling Water System Program (B.2.1.17)
* Closed-Cycle Cooling Water System Program (B.2.1.18)
* Fire Water System Program (B.2.1.24)
* Fire Protection Program (B.2.1.23)
* Compressed Air Monitoring Program (B.2.1.21)
* ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program (B.2.1.4)
* BWR Stress Corrosion Cracking Program (B.2.1.10)
* BWR Reactor Water Cleanup System Program (B.2.1.22)
* Flow-accelerated Corrosion Program (B.2.1.15)
* Inspection of Overhead Heavy Load and Light Load Handling Systems Program (B.2.1.20)
* Diesel Starting Air Program (B.2.1.41)
Staff Evaluation. In LRA Tables 3.3.2-1 through 3.3.2-34, the applicant provided a summary of AMRs for the auxiliary system s components, and identified which AMRs it considered to be consistent with the GALL Report.
For component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report does not recommend further
 
evaluation, the staff performed an audit and review to determine whether the plant-specific
 
components contained in these GALL Report component groups were bounded by the GALL
 
Report evaluation.
The applicant provided a note for each AMR line item. The notes described how the information in the tables aligns with the information in the GALL Report. The staff audited those AMRs with
 
Notes A through E, which indicated that the AMR was consistent with the GALL Report.
Note A indicated that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the AMP 3-208 identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site-specific conditions.
Note B indicated that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP
 
identified in the GALL Report. The staff audited these line items to verify consistency with the
 
GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been
 
reviewed and accepted by the staff. The staff also determined whether the AMP identified by the
 
applicant was consistent with the AMP identified in the GALL Report and whether the AMR was
 
valid for the site-specific conditions.
Note C indicated that the component for the AMR line item is different from but consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent
 
with the AMP identified by the GALL Report. This note indicates that the applicant was unable to
 
find a listing of some system components in the GALL Report. However, the applicant identified
 
a different component in the GALL Report that had the same material, environment, aging
 
effect, and AMP as the component that was under review. The staff audited these line items to
 
verify consistency with the GALL Report. The staff also determined whether the AMR line item
 
of the different component was applicable to the component under review and whether the AMR
 
was valid for the site-specific conditions.
Note D indicated that the component for the AMR line item is different from but consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some
 
exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify
 
consistency with the GALL Report. The staff verified whether the AMR line item of the different
 
component was applicable to the component under review. The staff verified whether the
 
identified exceptions to the GALL AMPs had been reviewed and accepted by the staff. The staff
 
also determined whether the AMP identified by the applicant was consistent with the AMP
 
identified in the GALL Report and whether the AMR was valid for the site-specific conditions.
Note E indicated that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited. The staff audited these line items
 
to verify consistency with the GALL Report. The staff also determined whether the identified
 
AMP would manage the aging effect consistent with the AMP identified by the GALL Report and
 
whether the AMR was valid for the site-specific conditions.
The staff conducted an audit and review of the information provided in the LRA, as documented in the BFN audit and review report. The staff did not repeat its review of the matters described in
 
the GALL Report. However, the staff did verify that the material presented in the LRA was
 
applicable and that the applicant had identified the appropriate GALL Report AMRs. The staff's
 
evaluation is discussed below.
The staff conducted an audit and review of the information provided in the LRA, as documented in the BFN audit and review report. The staff did not repeat its review of the matters described in
 
the GALL Report; however, the staff did verify that the material presented in the LRA was
 
applicable and that the applicant had identified the appropriate GALL Report AMRs.
The staff reviewed the LRA to confirm that the applicant had (1) provided a brief description of the system, components, materials, and environment, (2) stated that the applicable aging 3-209 effects were reviewed and evaluated in the GALL Report, and (3) identified those aging effects for the auxiliary systems components that are subj ect to an AMR. On the basis of its audit and review, the staff determined that, for AMRs not requiring further evaluation, as identified in LRA
 
Table 3.3.1, the applicant's references to the GALL Report are acceptable and no further staff
 
review is required.
Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating
 
experience and proposals for managing associated aging effects. On the basis of its review, the
 
staff concluded that the AMR results that the applicant claimed to be consistent with the GALL
 
Report are, in fact, consistent with the AMRs in the GALL Report. Therefore, the staff concluded
 
that the applicant had demonstrated that the effects of aging for these components will be
 
adequately managed so that their intended function(s) will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR54.21(a)(3).3.3.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended Summary of Technical Information in the Application. In LRA Section 3.3.2.2, the applicant provided further evaluation of aging management as recommended by the GALL Report for the auxiliary systems. The applicant provided info rmation concerning how it will manage the following aging effects:
* loss of material due to general, pitting, and crevice corrosion
* hardening and cracking or loss of strength due to elastomer degradation or loss of material due to wear
* cumulative fatigue damage
* crack initiation and growth due to cracking or stress corrosion cracking
* loss of material due to general, microbiologically influenced, pitting, and crevice corrosion
* loss of material due to general, galvanic, pitting, and crevice corrosion
* loss of material due to general, pitting, crevice, and microbiologically influenced corrosion and biofouling
* quality assurance for aging management of non-safety-related components
* cracking initiation and growth due to stress corrosion cracking and cyclic loading
* reduction of neutron-absorbing capacity and loss of material due to general corrosion
* loss of material due to general, pitting, crevice, and microbiologically influenced corrosion Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report recommends further
 
evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it
 
adequately addressed the issues that were further evaluated. In addition, the staff reviewed the
 
applicant's further evaluations against the criteria in SRP-LR Section 3.3.2.2. Details of the 3-210 staff's audit are documented in the staff's BFN audit and review report. The staff's evaluation of the aging effects is discussed in the following sections.
3.3.2.2.1  Loss of Material due to General, Pitting, and Crevice Corrosion
 
The staff reviewed LRA Section 3.3.2.2.1 against the criteria in SRP-LR 3.3.2.2.1.
 
In LRA Section 3.3.2.2.1, the applicant addressed the further evaluation of programs to manage loss of material in components of the spent fuel pool cooling and cleanup system.
SRP-LR Section 3.3.2.2.1 states that loss of material due to general, pitting, and crevice corrosion could occur in the channel head and access cover, tubes, and tubesheets of the heat
 
exchanger in the spent fuel pool cooling and cleanup system. The Chemistry Control Program relies on monitoring and control of reactor water chemistry based on EPRI guidelines of
 
TR-105714 for primary water chemistry and TR-102134 for secondary water chemistry to
 
manage the effects of loss of material from general, pitting or crevice corrosion. However, high
 
concentrations of impurities at crevices and locations of stagnant flow conditions could cause
 
general, pitting, or crevice corrosion. Therefore, verification of the effectiveness of the chemistry
 
control program should be performed to ensure that corrosion is not occurring. The GALL
 
Report recommends further evaluation of progr ams to manage loss of material from general, pitting, and crevice corrosion to verify the effe ctiveness of the Chemistry Control Program. A one-time inspection of select components at susceptible locations is an acceptable method for
 
ensuring that corrosion is not occurring and that the component's intended function will be
 
maintained during the period of extended operation. No loss of material aging effects are
 
observed for stainless steel components exposed to air.
Further, SRP-LR Section 3.3.2.2.1 states that loss of material due to pitting and crevice corrosion could occur in the filter housing, valve bodies, and nozzles of the ion exchanger in the
 
spent fuel pool cooling and cleanup system.
The Chemistry Control Program relies on monitoring and control of reactor water chemistry based on EPRI guidelines of TR-105714 for
 
primary water chemistry and TR-102134 for secondary water chemistry to manage the effects of
 
loss of material from pitting or crevice corrosion. However, high concentrations of impurities at
 
crevices and locations of stagnant flow conditions could cause pitting, or crevice corrosion.
 
Therefore, verification of the effectiveness of the Chemistry Control Program should be
 
performed to ensure that corrosion is not occurring. The GALL Report recommends further
 
evaluation of programs to manage loss of materi al from pitting and crevice corrosion to verify the effectiveness of the Chemistry Control Program. A one-time inspection of select
 
components at susceptible locations is an acceptable method to ensure that corrosion is not
 
occurring and that the component's intended function will be maintained during the period of
 
extended operation.
The applicant stated that the portion of the fuel pool cooling and cleanup (FPC) system that contains components requiring an AMR includes the water filled piping within the reactor
 
building, and the applicant credited the Chemistry Control Program and One-Time Inspection
 
Program to manage loss of material. The Chemistr y Control Program is credited with managing loss of material for stainless steel components in this portion of the spent fuel pool cooling and
 
cleanup system that are exposed to treated water. The One-Time Inspection Program, which
 
addresses the verification program recommendation in the GALL Report, provides for the 3-211 inspection of systems to verify that AMPs ar e effective and that aging effects are not occurring.
This is consistent with the GALL Report and acceptable to the staff.
3.3.2.2.2  Hardening and Cracking or Loss of Strength due to Elastomer Degradation or Loss of Material due to Wear The staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR 3.3.2.2.2.
 
In LRA Section 3.3.2.2.2, the applicant addressed the further evaluation of programs to manage the potential for degradation of elastomers in collars and seals in spent fuel cooling systems
 
and ventilation systems.
SRP-LR Section 3.3.2.2.2 states that hardening and cracking due to elastomer degradation could occur in elastomer linings of the filter, valve, and ion exchangers in spent fuel pool cooling
 
and cleanup systems. Hardening and loss of strength due to elastomer degradation could occur
 
in the collars and seals of the duct and in the elastomer seals of the filters in the control room
 
area, auxiliary and radwaste area, and primary containment heating ventilation systems and in the collars and seals of the duct in the diesel generator building ventilation system. Loss of
 
material due to wear could occur in the collars and seals of the duct in the ventilation systems.
 
The GALL Report recommends further evaluation to ensure that these aging effects are
 
adequately managed.
In LRA Section 3.3.2.2.2, the applicant stated that elastomers are not used in components subject to an AMR in the spent fuel cooling and cleanup system. The applicant also stated that
 
for the ventilation systems, hardening and loss of strength due to elastomer degradation is
 
dependent on environmental conditions. The applicant also stated that loss of material due to
 
wear of elastomer components is managed by the systems monitoring program if the environmental threshold is exceeded. The staff found this acceptable.
The staff noted that LRA Table 3.3.2.28 identifies elastomer degradation due to thermal exposure as an AERM for flexible connectors in the diesel generator ventilation system having an internal environment of air/gas. The applicant credited the One-Time Inspection Program to
 
manage this aging effect and claimed consistency with GALL Report, Item VII.F4.1-b, referencing Table 3.2.1, Item 3.3.1.2. However, Table 3.2.1, Item 3.3.1.2 refers to the further
 
evaluation in LRA Section 3.3.2.2.2, which stat es that the Systems Monitoring Program will be used to manage hardening and loss of strength of elastomers in ventilation systems. The staff
 
during the onsite audit requested the applicant to explain why the One-Time Inspection Program
 
was credited for managing elastomer aging for flexible connectors in the diesel generator
 
ventilation system. In its formal response, by letter dated October 8, 2004, the applicant stated
 
that the One-Time Inspection Program is credited for the inspection of elastomers where the
 
degradation mechanism may be internal. The Systems Monitoring Program is credited for the
 
inspection of elastomers where the degradation mechanism may be external. The applicant
 
stated that LRA Section 3.3.2.2.2 should include a discussion of the One-Time Inspection
 
Program for internal surfaces of elastomers. If degradation is found to be present, additional
 
inspections and corrective actions may be required by the One-Time Inspection Program. The
 
staff found this acceptable.
3-212 3.3.2.2.3  Cumulative Fatigue Damage In LRA Section 3.3.2.2.3, the applicant stated that fatigue is a TLAA, as defined in 10 CFR 54.3.
Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4
 
documents the staff's review of the applicant's evaluation of this TLAA.
3.3.2.2.4  Crack Initiation and Growth due to Cracking or Stress Corrosion Cracking
 
The staff reviewed LRA Section 3.3.2.2.4 against the criteria in SRP-LR 3.3.2.2.4.
 
In LRA Section 3.3.2.2.4, the applicant addressed the further evaluation of programs to manage the potential for cracking in the regenerative and non-regenerative heat exchanger components
 
in the reactor water cleanup system.
SRP-LR Section 3.3.2.2.4 addresses crack initiation and growth due to SCC in the regenerative and non-regenerative heat exchanger components in the reactor water cleanup system. The GALL Report recommends further evaluation to ensure that these aging effects are managed
 
adequately.
The applicant stated that it uses the Chemistry Control Program and the One-Time Inspection Program to manage cracking and SCC of these stainless steel components. In the ESF section
 
of the GALL Report, Volume 2, Item V.D2.1-c, the management of stainless steel components
 
performing a pressure boundary function is address ed by using the Chemistry Control Program.
Therefore, the applicant's use of the Chemistry Control Program to manage crack initiation and
 
growth due to SCC is consistent with the GALL Report and, therefore, is acceptable to the staff.
3.3.2.2.5  Loss of Material due to General, Microbiologically Influenced, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.3.2.2.5 against the criteria in SRP-LR 3.3.2.2.5.
 
In LRA Section 3.3.2.2.5, the applicant addressed the further evaluation of programs to manage the loss of material from corrosion that could occur on internal and external surfaces of
 
components exposed to air and the associated range of atmospheric conditions.
SRP-LR Section 3.3.2.2.5 states that loss of material due to general, pitting, and crevice corrosion could occur in the piping and filter housing and supports in the control room area; the
 
auxiliary and radwaste area; the primary cont ainment heating and ventilation systems; the piping of the diesel generator building ventilation system; the above ground piping and fittings, valves, and pumps in the diesel fuel oil system and in the diesel engine starting air, combustion air intake, and combustion air exhaust subsystems in the EDG system. Loss of material due to
 
general, pitting, crevice, and MIC could occur in the duct fittings, access doors, and closure
 
bolts, equipment frames and housing of the duct. Loss of materials due to pitting and crevice
 
corrosion could occur in the heating/cooling coils of the air handler heating/cooling. Loss of
 
material due to general corrosion could occur on the external surfaces of all carbon steel SCs, including bolting exposed to operating temperatures less than 212 °F in the ventilation systems.
The GALL Report recommends further evaluation to ensure that these aging effects are
 
adequately managed.
3-213 The applicant credited the One-Time Inspection Program for managing loss of material due to corrosion of carbon and low-alloy steel, cast iron/cast iron alloy, and copper alloy components in
 
the off-gas, heating, ventilation, and air conditioning, diesel generator, reactor core isolation
 
cooling, raw cooling water, diesel generator starting air, ventilation, standby liquid control, and
 
demineralizer backwash air systems with inter nal surfaces exposed to air/gas. The staff found this acceptable.
The applicant credited the Systems Monitoring Program for managing loss of material due to corrosion of carbon and low-alloy steel components in the auxiliary boiler, fuel oil, RHRSW, raw
 
cooling water, raw service water, high pressure fire protection, potable water ventilation, HVAC, control air, service air, CO 2 , station drainage, sampling and water quality, building heat, raw water chemical treatment, demineralizer ba ckwash air, standby liquid control, off-gas, emergency equipment cooling water, reactor water cleanup, reactor building closed cooling
 
water, reactor core isolation cooling, radioactive waste treatment, fuel pool cooling and cleanup, diesel generator, CRD, diesel generator starting air, and radiation monitoring systems with
 
external surfaces exposed to air. The staff found this acceptable.
The applicant credited the Diesel Starting Air Program for managing loss of material due to corrosion of carbon and low-alloy steel components in the diesel generator starting air system
 
with internal surfaces exposed to air/gas. The staff found this acceptable.
The staff noted that LRA Table 3.3.2.28 identifies loss of material due to crevice, general, and pitting corrosion as an AERM for carbon and low-alloy steel components in a treated water
 
environment. LRA Table 3.2.1, Item 3.3.1.5 is referenced and consistency with the GALL Report
 
is noted. The Closed-Cycle Cooling Water Program is credited for managing this aging effect.
 
However, LRA Table 3.2.1, Item 3.3.1.5 references the further evaluation in 3.3.2.2.5, which
 
pertains to components in an air environment, and does not include the Closed-Cycle Cooling
 
Water Program as one of the programs to manage aging. The staff inquired as to why LRA
 
Table 3.2.1, Item 3.3.1.5 was referenced for these components. By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that LRA Table 3.3.2.28
 
for the diesel generator system has six line items with a treated water environment that match
 
the GALL Report. The correct GALL Report, Volume 1, Table 1 reference for the items that
 
match the GALL Report is Item 3.3.1.15. Five of the LRA Table 3.3.2.28 treated water line items
 
correctly reference 3.3.1.15; one incorrectly references 3.3.1.5. The reference to 3.3.1.5 should
 
be 3.3.1.15. The staff reviewed this response and concluded that it is acceptable.
3.3.2.2.6  Loss of Material due to General, Galvanic, Pitting, and Crevice Corrosion
 
In LRA Section 3.3.2.2, the applicant addressed the further evaluation of programs to manage loss of material in the reactor coolant pump oil collection system to verify the effectiveness of the Fire Protection Program. The applicant stated that this aging effect is not applicable to BFN
 
since the BFN design does not include a recirculation pump oil collection system. The staff
 
concluded that this is acceptable since the BFN design does not include a reactor coolant pump oil collection system.
3-214 3.3.2.2.7  Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced Corrosion and Biofouling The staff reviewed LRA Section 3.3.2.2.7 against the criteria in SRP-LR 3.3.2.2.7.
 
In LRA Section 3.3.2.2.7, the applicant addressed the further evaluation of programs to manage loss of material in the diesel fuel oil system to verify the effectiveness of the diesel fuel
 
monitoring program.
SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevice corrosion, MIC, and biofouling could occur in the internal surface of tanks in the diesel fuel oil
 
system and due to general, pitting, and crevice corrosion and MIC in the tanks of the diesel fuel
 
oil system in the EDG system. The existing AM P relies on the Fuel Oil Chemistry Program for monitoring and control of fuel oil contamination in accordance with the guidelines of ASTM
 
Standards D4057, D1796, D2709 and D2276 to manage loss of material due to corrosion or
 
biofouling. Corrosion or biofouling may occur at locations where contaminants accumulate.
 
Verification of the effectiveness of the chemistry control program should be performed to ensure
 
that corrosion is not occurring. The GALL Report recommends further evaluation of programs to
 
manage corrosion/biofouling to verify the effectiveness of the program. A one-time inspection of
 
selected components at susceptible locations is an acceptable method to ensure that corrosion
 
is not occurring and that the component's intended function will be maintained during the period
 
of extended operation.
In LRA Section 3.3.2.2.7, the applicant stated that it uses the Fuel Oil Chemistry Program to manage loss of material for the diesel fuel oil system. In addition, the applicant will use the
 
One-Time Inspection Program to verify the effe ctiveness of the fuel oil chemistry program. The inspection will ensure that corrosion is not occurring at locations where contaminants
 
accumulate. The One-Time Inspection Program addresses the one-time inspection
 
recommendation in the GALL Report.
The staff reviewed the Fuel Oil Chemistry Program and found that the program will adequately manage the effects of aging so that the intended functions will be maintained. The staff also
 
reviewed the One-Time Inspection Program, which will be used to verify the effectiveness of the
 
Fuel Oil Chemistry Program.
3.3.2.2.8  Quality Assurance for Aging Management of Non-Safety-Related Components SER Section 3.0.4 provides the staff's evaluation of the applicant's quality assurance program.3.3.2.2.9  Cracking Initiation and Growth due to Stress Corrosion Cracking and Cyclic Loading
 
Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3-215 3.3.2.2.10  Reduction of Neutron-Absorbing Capacity and Loss of Material due to General Corrosion The staff reviewed LRA Section 3.3.2.2.10 against the criteria in SRP-LR 3.3.2.2.10.
 
In LRA Section 3.3.2.2.10, the applicant addressed the further evaluation of programs to manage reduction of neutron-absorbing capacity and loss of material due to general corrosion, which could occur in the neutron absorbing sheets of the spent fuel storage rack in the spent
 
fuel storage.
SRP-LR Section 3.3.2.2.10 states that reduction of neutron-absorbing capacity and loss of material due to general corrosion could occur in the neutron-absorbing sheets of the spent fuel
 
storage rack in the spent fuel storage. The GALL Report recommends further evaluation to
 
ensure that these aging effects are adequately managed.
The applicant stated that boral is used as a neutron absorbing material in the spent fuel pools.
Reduction of neutron absorbing capacity and loss of material due to general corrosion could
 
occur in the boral neutron absorbing material in spent fuel storage racks. The Chemistry Control
 
Program manages general corrosion. An inspection of boral coupon test specimens was
 
performed that confirmed no significant aging degradation had occurred and the neutron
 
absorbing capability of the boral had not been reduced. Reduction of neutron absorbing
 
capacity and loss of material due to general corrosion will be managed by the Chemistry Control
 
Program. The staff reviewed the Chemistry Control Program and found that the program will adequately manage the effects of aging so that the intended functions will be maintained.
3.3.2.2.11  Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced Corrosion The staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR 3.3.2.2.11.
 
In LRA Section 3.3.2.2.11, the applicant addressed the further evaluation of programs to manage the potential for loss of material in buried piping of the service water and diesel fuel oil systems.SRP-LR Section 3.3.2.2.11 states that loss of material due to general, pitting, and crevice corrosion and MIC could occur in the underground piping and fittings in the OCCW system and
 
in the diesel fuel oil system. The buried piping and tanks inspection program relies on industry
 
practice, frequency of pipe excavation, and operating experience to manage the effects of loss
 
of material from general, pitting, and crevice corrosion and MIC. The effectiveness of the buried
 
piping and tanks inspection program should be verified to evaluate an applicant's inspection
 
frequency and operating experience with buried components, ensuring that loss of material is
 
not occurring.
The applicant credited the Buried Piping and Tanks Inspection Program for managing loss of material for buried components of the service water and diesel fuel oil systems. This is consistent with GALL AMP XI.M34, "Buried Piping Inspection." The staff reviewed the
 
applicant's operating history and found that the frequency of pipe excavation was sufficient to 3-216 manage the effects of loss of material. The staff reviewed the Buried Piping Inspection Program and concluded that it is acceptable.
3.3.2.2.12  Evaluation of Auxiliary Systems AMRs That Reference Further Evaluations Not Included Under Auxiliary Sysyems In the AMR for components in the auxiliary syst ems, the applicant referenced several further evaluations that are included under systems ot her than the auxiliary systems. These further evaluations were referenced based on applicability to the material, environment, and aging
 
effect identified for components in the auxilia ry systems. The staff reviewed these further evaluations for applicability to the auxiliary sy stems; the assessment is documented in the following subsections.
Crack Initiation and Growth due to SCC, IGSCC, and Thermal and Mechanical Loading. In LRA Section 3.1.2.2.4, the applicant addressed the further evaluation of programs to manage crack
 
initiation and growth due to thermal and mechanical loading or stress corrosion cracking of
 
components in the reactor coolant system. This aging effect is referenced in LRA Table 3.2.1, Item 3.1.1.7, which the applicant referenced in the auxiliary systems AMRs for components in the sampling and water quality, standby liquid control, reactor water cleanup, reactor core
 
isolation cooling, and neutron monitoring systems.
The staff noted that the LRA identifies crack initiation/growth due to cyclic loading as an AERM for various mechanical components in the sampling and water quality, standby liquid control, reactor water cleanup, reactor core isolation cooling, and neutron monitoring systems. The
 
ASME ISI Program and One-Time Inspection Progr am are credited to manage this aging effect.
The staff noted similar entries in the AMRs for the ESF systems and the reactor coolant system.
The staff inquired as to why the Chemistry Control Program had been not included to manage
 
this aging effect for these components since the Chemistry Control Program is included in the
 
further evaluation in LRA Section 3.1.2.2.4. The applicant's response and the staff's evaluation
 
are addressed in SER Section 3.1.2.2.4.
Loss of Material due to General Corrosion. In LRA Section 3.2.2.2.2, the applicant addressed the further evaluation of programs to manage loss of material due to general corrosion for
 
components in the ESF systems. This aging effect is referenced in LRA Table 3.2.1, Items
 
3.2.1.2, 3.2.1.3, and 3.2.1.10, which the applicant referenced in the auxiliary systems AMRs for components in the auxiliary boiler, raw service water, potable water, service air, station
 
drainage, sampling and water quality, building heat, demineralizer backwash air, off-gas, reactor
 
core isolation cooling, radioactive waste treatment, CRD, and radiation monitoring systems. The
 
staff reviewed the applicant's further evaluation for this aging effect in SER Section 3.2.2.2.
The staff noted that the LRA identifies loss of material due to general, crevice, and pitting corrosion as an AERM for mechanical components in a treated water environment in the
 
radioactive waste treatment system (LRA Table 3.3.2.25). LRA Table 3.2.1, Items 3.2.1.3 and
 
3.2.1.5 are referenced and consistency with the GALL Report is noted. The One-Time
 
Inspection Program is credited for managing this aging effect; however, the further evaluation in
 
the LRA Section 3.2.2.2.2 identifies the Chemistry Control Program for managing the effects of
 
corrosion for components in a treated water environment. During the onsite audit, the staff
 
inquired as to the technical basis for using the One-Time Inspection Program alone to manage
 
aging due to corrosion for components in a treated water environment, instead of the Chemistry 3-217 Control program. By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the treated water in the radioactive waste treatment system is waste that
 
was generated from systems that contain chemis try control treated water; however, once this water becomes a waste steam, the chemistry can no longer be controlled. Since the portions of
 
the system exposed to treated water have their wa ter source from chemistry control systems, the potential for corrosion is low. The One-Time Inspection Program will verify this by
 
performing a sampling inspection. If corrosion is found to be present, additional inspections and
 
corrective actions may be required by the One-Time Inspection Program.
The staff reviewed the applicant's response and concluded that it is acceptable since the water in the radioactive waste treatment system is waste that was generated from systems that contain chemistry control treated water. Once the treated water becomes a waste stream the
 
chemistry can no longer be controlled, which is why the Chemistry Control Program is not
 
credited for this aging effect. The potential for corrosion is low for these components and the
 
One-Time Inspection Program will be performed to verify that corrosion is not occurring.
The staff noted that LRA Tables 3.3.2.3, 3.3.2.5, 3.3.2.14, 3.3.2.21, and 3.3.2.25 identify loss of material due to biofouling, MIC, crevice corrosion, general corrosion, and pitting corrosion as an
 
AERM for stainless steel components in a raw water environment. LRA Table 3.2.1, Items
 
3.2.1.3, 3.2.1.5, and 3.2.1.6 are referenced and consistency with the GALL Report is noted.
 
LRA Table 3.2.1, Items 3.2.1.3, 3.2.1.5 and 3.2.1.6 reference further evaluations in LRA
 
Sections 3.2.2.2.2. 3.2.2.2.3, and 3.2.2.2.4, respectively. However, LRA Sections 3.2.2.2.2 and
 
3.2.2.2.3 pertain to components in treated water, for which the Chemistry Control and One-Time
 
Inspection Programs are identified to manage this aging effect. Only LRA Section 3.2.2.2.4
 
pertains to components in raw water. The staff asked why LRA Table 3.2.1, Items 3.2.1.3 and
 
3.2.1.5 are referenced for these components. The staff also inquired as to the technical basis
 
for using the One-Time Inspection Program to manage aging due to MIC for the components in
 
Table 3.3.2.25 instead of the Open-Cycle Cooling Water Program. By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that LRA
 
Sections 3.2.2.2.2 and 3.2.2.2.3 only address treated water environments and should include a
 
discussion of the Open-Cycle Cooling Water Program for raw water systems.
The staff found this acceptable, because the applicant indicated that LRA Sections 3.2.2.2.2 and 3.2.2.2.3 should also include raw water environments and credited the Open-Cycle Cooling
 
Water Program for raw water systems. With these additions, the applicant's AMR results will be
 
consistent with the GALL Report.
Loss of Material due to Pitting and Crevice Corrosion. In LRA Section 3.2.2.2.3, the applicant addressed the further evaluation of programs to manage the loss of material due to pitting and
 
crevice corrosion for components in the engineered sa fety feature systems. This aging effect is referenced in LRA Table 3.2.1, Items 3.2.1.4 and 3.2.1.5, which the applicant referenced in the
 
auxiliary systems AMRs for co mponents in the raw service water, sampling and water quality, building heat, reactor core isolation cooling, auxiliary decay heat removal, radioactive waste
 
treatment, CRD, and radiation monitoring systems. The staff reviewed the applicant's further
 
evaluation for this aging effect in SER Section 3.2.2.3.
3-218 The staff noted that the LRA identified loss of material due to crevice and pitting corrosion as an AERM for mechanical components in a treated water environment in the radiation monitoring
 
system (LRA Table 3.3.2.31). The applicant referenced LRA Table 3.2.1, Item 3.2.1.5 and
 
consistency with the GALL Report is noted. The Closed-Cycle Cooling Water Program is
 
credited for managing this aging effect. However, the further evaluation in LRA Section 3.2.2.2.3
 
identifies the Chemistry Control Program and One-Time Inspection Program for managing the effects of corrosion for components in a treated water environment. The staff inquired as to the
 
technical basis for using the Closed-Cycle Cooling Water Program alone to manage aging due
 
to corrosion for components in a treated water environment instead of the Chemistry Control
 
Program and One-Time Inspection Program. By letter dated October 8, 2004, the applicant
 
submitted its formal response to the staff, stating that the Closed-Cycle Cooling Water Program is consistent with the related GALL Report Closed-Cycle Cooling Water Program (XI.M21). The
 
Closed-Cycle Cooling Water Program provides for prevention and detection of aging effects in plant closed cycle cooling water systems. LRA Section 3.2.2.2.3 only addresses treated water
 
environments and should include a discussion of t he Closed-Cycle Cooling Water Program for treated water in closed cooling loops.
The staff found this acceptable because the applicant indicated that LRA Section 3.2.2.2.3 should also include treated water in closed cooling loops and credit the Closed-Cycle Cooling
 
Water Program.
Local Loss of Material due to Microbiologically Influenced Corrosion. In LRA Section 3.2.2.2.4, the applicant addressed the further evaluation of programs to manage the local loss of material
 
due to MIC for components in the engineered safety feature systems. This aging effect is
 
referenced in LRA Table 3.2.1, Item 3.2.1.6, which the applicant referenced in the auxiliary
 
systems AMRs for components in the raw service water, sampling and water quality, radioactive
 
waste treatment, and radiation monitoring systems. The staff reviewed the applicant's further
 
evaluation for this aging effect in SER Section 3.2.2.2.4.
The staff noted that LRA Table 3.3.2.25 identifies loss of material due to MIC as an AERM for components in a raw water environment in the radioactive waste treatment system. LRA Table 3.2.1, Items 3.2.1.3, 3.2.1.5, and 3.2.1.6, are referenced, and consistency with the GALL
 
Report is noted. The One-Time Inspection Program is credited to manage this aging effect.
 
However, Section 3.2.1.6 references the further evaluation in LRA Section 3.2.2.2.4, which
 
identifies the Open-Cycle Cooling Water Program for managing MIC. The staff inquired as to the
 
technical basis for crediting the One-Time Inspection Program for managing aging due to MIC
 
for these components. By letter dated October 8, 2004, the applicant submitted its formal
 
response to the staff, stating that the raw water environment identified in the radioactive waste
 
treatment system is waste that was generated from floor and equipment drain sumps and may
 
contain dirty or contaminated water. This waste stream is not subject to the Chemistry Control
 
Program or the Open-Cycle Cooling Water Progr am. The potential for corrosion in this system would be lower than actual "raw water" systems because a portion of the waste stream would
 
be treated water from chemistry control systems. The applicant determined that inspection in
 
accordance with the One-Time Inspection Program w ill verify integrity of this system during the period of extended operation. If corrosion is found to be present, additional inspections and
 
corrective actions may be required by the One-Time Inspection Program.
3-219 The staff reviewed the applicant's response and concluded that it is acceptable since the raw water environment identified in the radioactive waste treatment system is waste that was
 
generated from floor and equipment drain sumps and may contain dirty or contaminated water.
 
The potential for corrosion in this system would be lower than actual raw water systems
 
because a portion of the waste stream would be treated water from chemistry control systems.
The One-Time Inspection Program will verify in tegrity of this system during the period of extended operation.
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report
 
recommends further evaluation, the staff determined that (1) those attributes or features for
 
which the applicant claimed consistency with the GALL Report were indeed consistent, and (2)
 
the applicant had adequately addressed the issues that were further evaluated. The staff found
 
that the applicant had demonstrated that the effects of aging will be adequately managed so
 
that the intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).3.3.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.3.2.1 through 3.3.2.34, the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are not addressed
 
in the GALL Report.
In LRA Tables 3.3.2.1 through 3.3.2.34, the applicant indicated, via Notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a
 
line item in the GALL Report, and provided inform ation concerning how the aging effect will be managed. Specifically, Note F indicated that the material for the AMR line item component is not
 
evaluated in the GALL Report. Note G indicated that the environment for the AMR line item
 
component and material is not evaluated in the GALL Report. Note H indicated that the aging
 
effect for the AMR line item component, materi al, and environment combination is not evaluated in the GALL Report. Note I indicated that the aging effect identified in the GALL Report for the
 
line item component, material, and environment combination is not applicable. Note J indicated
 
that neither the component nor the material and environment combination for the line item is
 
evaluated in the GALL Report.
For component type, material, and environment combination that are not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant had
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation.
 
The staff's evaluation is discussed in the following sections.
During its review, the staff determined that similar AMR line items required clarification for several systems. In several of the auxiliary systems, the LRA states that copper alloy components in an inside air (external) environment experience no AERMs. However, the
 
existence of AERMs depends on the particular alloy and whether there is condensation or
 
pooling on the component. For example, high zinc (>15 percent) alloys in condensation or
 
pooling water may exhibit stress corrosion cracking, selective leaching, or pitting and crevice
 
corrosion. The LRA definition of inside air (external) would support condensation and pooling.
3-220 In RAI 3.3.2.1-1, dated October 12, 2004, the staff requested the applicant to clarify how condensation and pooling were considered in the evaluation of potential aging of susceptible
 
alloys. In its response, by letter November 3, 2004, the applicant stated that the copper alloy
 
components exposed to an inside air (external) environment were evaluated individually to determine where condensation could occur (i.e., components containing fluid at a temperature
 
below the dew point of the external environm ent). The aging effects evaluation then determined the aging effects/mechanisms based on the particular alloys are susceptible and whether
 
condensation or periodic wetting occurred. The applicant provided its guidelines for assessing
 
the particular alloys.
The staff reviewed the applicant's criteria for determining aging effects based on the particular copper alloy and found them acceptable and consistent with industry guidance. The applicant
 
evaluated the components individually and applied acceptable criteria for determining the
 
AERMs of the alloys exposed to condensation or pooling. Therefore, the staff found the
 
applicant's evaluation of copper alloys in inside air to be acceptable.
Aging Management of Bolting in Auxiliary Systems Bolting. The staff reviewed LRA Tables 3.3.2.1 through 34, which relates to the AMR evaluations for bolting in auxiliary systems bolting. The staff was concerned that cracking and loss of preload are not identified as aging
 
effects for bolting managed by the Bolting Integrity Program, including bolting subject to high
 
pressure, high temperature or vibration. The Bolting Integrity Program should provide for bolting
 
preload control for all bolting within scope of license renewal.
The LRA AMR tables credit the Bolting Integrity Program for managing loss of bolting function due to various corrosion mechanisms in auxiliary systems bolting. Loss of preload and cracking are not identified as aging effects for bolting in the AMR tables for auxiliary systems.GALL AMP XI.M18 specifically credits the Bolting Integrity Program developed and implemented in accordance with commitments made in response to communications on bolting
 
events to provide an effective means of ens uring bolting reliability. The program relies on industry recommendations for a comprehensive bolting maintenance, as delineated in EPRI
 
TR-104213 for pressure retaining bolting. The program covers all bolting within the scope of
 
license renewal. The GALL Report includes loss of material, cracking and loss of preload as
 
aging effects. Bolting preload control, as delineated in EPRI NP-5769 with exceptions noted in
 
NUREG-1339, is applied to manage loss of preload. NUREG CR-6679 also identifies loss of
 
preload as an aging effect and the draft GALL Report update 2005 includes loss of preload as
 
an aging effect for bolting in ESF, auxiliary and S&PC systems. Further, SRP-LR
 
Section A.1.2.1 states, "However leakage from bolted connections should not be considered
 
abnormal events. Although bolting connections are not supposed to leak, experience has shown
 
that leaks do occur, and the leakage could cause corrosion. Thus, the aging effects from
 
leakage of bolted connections should be evaluated for license renewal." The Bolting Integrity Program is identified as an existing program that takes exceptions to GALLAMP XI.M18 evaluation elements. The exceptions affect element 1 - scope of the program and possibly element 4 - detection of aging effects. It appears that Element 4 - detection of aging
 
effects - is identified as being affected by the exceptions. The applicant credits ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program for ASME Section XI
 
inspections of Class 1 and Class 2 bolting.
3-221 For auxiliary system closure bolting, the staff is concerned that cracking and loss of preload arenot entirely addressed by either the ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program or Bolting Integrity Program. Although ASME Section XI requires
 
bolt torquing loads to be in accordance with ASME Section III for replacement of Class 1 and 2
 
bolting, no bolt torquing requirements are specified for Class 3 bolting, NSR bolting or bolting that is reused after being removed for maintenance. ASME Section XI does address
 
examination of Class 1 bolting, but no examinati on is required for Class 2 bolting smaller than 2inch and Class 3 bolting regardless of size or NSR bolting. ASME Section XI does provide for
 
inspection during leakage testing, but this inspection may not necessarily detect loss of preload or flange leakage at other times. GALL AMP XI.M18, "Bolting Integrity," does manage cracking
 
and loss of preload in all closure bolting within scope of license renewal. As identified in EPRI
 
NP-5769, preload reduction is caused by a number of factors, including stress relaxation (both
 
at room temperature and elevated temperature), t hermal cycling (particularly for gaskets), creep and flow of gasket material during initial compression, vibration and shock, and elastic
 
interactions between separately-tightened bolts. The GALL Report includes high pressure and
 
high temperature systems as being susceptible to crack initiation. Therefore, the applicantshould clarify if the bolting integrity AMP is consistent with GALL AMP XI.M18 in regard to
 
managing cracking and loss of preload or explain how these aging effects are managed by
 
other programs or maintenance practices.
By letter dated October 8, 2004, the applicant provided additional information in response to Audit Inspection Question 310 on bolting activities. The applicant stated that, "Structural bolting
 
procurement activities, receipt inspection and installation (torquing), as defined in TVA
 
procedure General Engineering Specification (GES) G-29B-S01, P.S.4.M.4.4, ASME Section III
 
and Non-Section III (including American Institute of Steel Construction (AISC), ANSI B31.1, and
 
ANSI B31.5) bolting material, are considered part of the Bolting Integrity Program and meet the
 
industry recommendations for these activities as delineated in NUREG-1339 and EPRI
 
NP-5769. By letter dated March 16, 2005, the applicant responded to the clarification request on bolting.
For valve closure bolting not within the RCPB, the applicant clarified that stress relaxation is a
 
thermal effect that results in loss of preload. The applicant explained that stress relaxation is a
 
design driven effect that would be detected and corrected early and is not considered an
 
applicable aging effect in non-RCPB valve closure bolting. The applicant stated that installation
 
procedures are in place that specify proper bolting installation practices and bolt torque values.
 
In this letter, the applicant also clarified that non-RCPB bolting is not susceptible to SCC as the
 
yield strength is less than 150 ksi. Further, the applicant explained that crack initiation and
 
growth due to cyclic loading is not considered a license renewal concern due to high cycle
 
fatigue, since it would be discovered and corrected during the current licensing period.
The staff reviewed the applicant's response and agreed that loss of preload in auxiliary system closure bolting should be managed by proper bolting installation practices and torque values
 
supplemented by inspections. The staff also concurred that proper bolting practices and the
 
selection of bolting less than 150 ksi should result in auxiliary system closure bolting not being
 
susceptible to SCC.
However, the staff did not agree that cracking and loss of preload are not aging effects for license renewal, unless the applicant demonstrates that these potential adverse effects will be
 
corrected prior to the period of extended operation. LRA Section B.2.1.16 states that the BWR 3-222 fleet of plants, including BFN, has experienced bolting degradation issues. Plant-specific and industry operating experience should be reviewed to determine if the applicant's bolting
 
practices are effective in precluding loss of pr eload and cracking for all auxiliary system closure bolting within the scope of license renewal. For example, despite implementation of bolting
 
practices, recent industry operating experience such as LER 2005-01 for Fermi 2 demonstrates
 
the importance of sufficient bolt torque to prevent major gasket leakage in BWR auxiliary
 
systems such as reactor building closed cooling water (RBCCW). The applicant was requested
 
to review operating experience and submit the re sults of any self assessments, inspections or maintenance activities to determine if closure bolting in auxiliary syst ems will be effectively managed for cracking and loss of preload. This information should provide objective evidence to
 
support the conclusion that the effects of aging will be managed adequately so that the
 
component intended function(s) will be maintained during the period of extended operation. If by
 
a review of operating experience the applicant cannot demonstrate that effective bolting
 
practices are in place to manage cracking and loss of preload in auxiliary system closure bolting, the applicant should commit to a Bolting Integrity Program consistent with the GALL
 
Report or explain how these aging effects are managed by other programs or maintenance practices.
 
By letter dated June 3, 2005, the applicant provided additional information concerning cracking
 
and loss of preload in auxiliary systems bolting. In this response the applicant included
 
information relevant to their review of operating experience with bolting.
Cracking - The applicant clarified that high yield strength heat-treated alloy steel bolting materials are not specified for flanged connections at BFN. The applicant also clarified that the
 
use of MoS 2 thread lubricant is not allowed by site and engineering procedures. Further the applicant clarified that a review of the operating experience had not identified any instances
 
where mechanical component failure was attributable to stress corrosion cracking of high
 
strength pressure boundary bolting. Thus, the applicant concluded that the aging effect loss of
 
bolting function was not identified at BFN because both the susceptible material and corrosive
 
environment portions of the stress corrosion crack mechanism are not present.
Loss of Preload - The applicant clarified that loss of preload due to stress relaxation (creep) is not an aging effect for standard grade B7 carbon steel bolting used in auxiliary system bolting with temperatures less than 700  °F. The applicant also clarified that BFN has taken actions to
 
address NUREG-1339, "Resolution to Generic Safety Issue 29; Bolting Degradation or Failure
 
in Nuclear Power Plants." These actions include the implementation of good bolting practices in
 
accordance with those referenced in EPRI NP-5769, with the exceptions noted in NUREG-1339, and EPRI TR-104213 to address the potential for joint failure such that it is not a concern for the
 
current or extended operating term. The applicant identified that a review of the BFN operating
 
experience did not identify any instances where the mechanical component failure was
 
attributable to loss of pressure boundary bolting preload. In regard to recent industry experience
 
with joint failures associated with loss of preload identified in Fermi 2 LER 2005-01, the
 
applicant attributed this failure to inadequate gasket compression due to a number of factors
 
including insufficient initial bolt torque. The applicant characterizes this failure as indicative of a
 
design/maintenance problem rather than an aging concern.
The staff reviewed the applicant's response dated March 16, 2005, and found the response to be reasonable and acceptable. The applicant provided additional information to clarify that
 
cracking and loss of preload in bolting are being effectively managed. However, the response 3-223 did not provide the results of any self assessments, inspections or maintenance activities, and operating experience to determine if closure bolting in auxiliary systems was effectively managed at BFN for cracking and loss of preload.
The staff discussed this issue with the applicant in a teleconference, and the verification of this confirmatory item was addressed during the AMP inspection performed on September 2005. The applicant also agreed to include
 
this in the Appendix A Commitment Table. In the inspection report, a letter dated November 8, 2005, the staff concluded that the bolting practices in BFN are functioning adequately. The staff, therefore, concluded that there is reasonable assurance that aging effects, including cracking
 
and loss of preload, for bolting used in auxilia ry systems are being and will continue to be effectively managed during the period of extended operation.
No Aging Effect or Aging Management Program Identified. The staff reviewed LRA Tables 3.3.2.1 through 3.3.2.34, which summarized the results of AMR evaluations for the
 
auxiliary systems component groups.
The applicant included entries in these tables for which there are no aging effects or AMPs identified. However, the material/environment combinations for these components do have
 
aging effects identified in other table entries. For example, LRA Table 3.3.2.31, row 14 shows
 
stainless steel fittings in treated water with no aging effect or AMP, while the next row has the
 
same component/material/ environment with loss of material identified as an AERM. The staff
 
inquired as to the purpose of the entries showing no aging effect or AMP. By letter dated
 
October 8, 2004, the applicant submitted its formal response to the staff, stating that the reason
 
for the line entries that indicate no aging effects is an attempt to ensure completeness of the
 
GALL Report comparison. For the example giv en, LRA Table 3.3.2.31, rows 14 and 15 address stainless steel fittings that form a portion of containment isolation. The applicable GALL Report, Volume 2 line item was determined to be V.C.1-b. GALL Report, Volume 2, Item V.C.1-b lists
 
four aging effects; pitting and crevice corrosion; MIC; and biofouling. For a treated water line, the AMR determined that MIC and biofouling did not require management for the period of
 
extended operation. This was documented in the AMR as:
* pitting corrosion - Yes
* crevice corrosion - Yes
* MIC - No
* biofouling - No The first two aging mechanisms form the basis for LRA Table 3.3.2.31, row 15. The last two are documented in LRA Table 3.3.2.31, row 14 as no aging effect with Note 4 identified. Note 4
 
states, "Based on system design and operating history, MIC and biofouling are not applicable to
 
the treated water portions of this system." Also, Table 3.3.2.14, row 58 should refer to Notes I, 5, and Table 3.3.2.28; row 56 should refer to Notes I, 2.
The staff found that the applicant's entries showing no aging effect or AMP are acceptable since they are included only to ensure completeness of the GALL Report comparison; and also
 
concurred with the corrections identified for LRA Table 3.3.2.14, row 58 and LRA
 
Table 3.3.2.28, row 56.
The staff reviewed LRA Tables 3.3.2.6, 3.3.2.9, 3.3.2.12, 3.3.2.14, 3.3.2.21, 3.3.2.22, 3.3.2.23, 3.3.2.28, 3.3.2.30, and 3.3.2.31, which summarize the results of AMR evaluations for the high
 
pressure fire protection; heating, ventilation, and air conditioning; CO 2, sampling and water 3-224 quality; reactor water cleanup; reactor building closed cooling water; reactor core isolation cooling; diesel generator; diesel generator starting air; and radiation monitoring systems
 
component groups, respectively.
The applicant identified glass fittings in environments of air/gas, inside air, treated water, raw water, lubricating oil, and aqueous film-forming foam (AFFF) as having no aging effects
 
requiring management. During the onsite audit, the staff inquired as to the specific applications
 
of these glass fittings and the chemical properties of AFFF with regard to its reactivity with
 
glass. By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the following components, which contain glass, are included within the scope of
 
license renewal for BFN:
* System 26, High Pressure Fire Protection - level gauge
* System 31, Heating, Ventilation, and Air Conditioning - level gauge
* System 37, Gland Seal Water - level gauge
* System 39, CO 2 - level gauge
* System 43, Sampling and Water Quality - level gauge
* System 64, Containment - level gauge
* System 68, Reactor Recirculation - sight glass
* System 70, Reactor Building Closed Cooling Water - level gauge
* System 82, Diesel Generator - level gauge
* System 86, Diesel Generator Starting Air - sight glass
* System 90, Radiation Monitoring - sight glass, moisture traps, and air filters In addition, the applicant stated that AFFF contains the following:
* water
* 2-(2-butoxyethoxy) ethanol
* ethylene glycol
* alkyl polyglycoside
* fluoroalkyl surfactant This mixture of hydrocarbons, surfactants, fluorosurfactants, and water is not reactive with glass.The staff concluded that the applicant's determination of no aging effect for these glass components for the environments identified is a cceptable since the environments identified are not reactive with glass.
3.3.2.3.1  Auxiliary Boiler System - Summary of Aging Management Evaluation - Table 3.3.2.1 The staff reviewed LRA Table 3.3.2.1, which summarizes the results of AMR evaluations for the auxiliary boiler system component groups.
In LRA Table 3.3.2.1, the applicant proposes that fittings, piping, and valves made from carbon and low-alloy steel in an environment of treated water (internal) and subjected to galvanic
 
corrosion will be managed by the One-Time Inspection Program.
3-225 The staff reviewed the One-Time Inspection Program and its evaluation is documented in SER Section 3.0.3.1. Galvanic corrosion is typically minimized through standard design practices.
 
Therefore, any galvanic corrosion is expected to be sufficiently slow that the One-Time Inspection Program is appropriate for this aging effect. If there is any significant galvanic
 
corrosion, this AMP will identify the problem and initiate appropriate corrective action. Therefore, the staff found the use of the One-Time Inspection Program to be appropriate for this aging
 
effect. LRA Section 3.3.2.1, states that valves made from copper alloy and exposed to inside air (external environment) experience no AERMs and require no AMPs.
In general RAI 3.3.2.1-1 the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
On the basis of its review of the information provided in the LRA and the additional information provided, the staff found the aging effects of the above AMR items are consistent with industry
 
experience for these combinations of materials and environments. The staff did not identify any
 
omitted aging effects. Therefore, the staff found that the applicant had identified the appropriate
 
aging effects for the materials and environments associated with the above components in the
 
auxiliary boiler system.
Loss of Material Due to Corrosion for Cast Iron and Carbon/Low Alloy Steels in an Air/Gas Environment The applicant identified loss of material due to crevice, general, and pitting corrosion as an AERM for valves constructed of cast iron and cast iron alloy, as well as fittings, piping, traps, and valves constructed of carbon or low-alloy steel in a moist air/gas environment
 
on their internal surface. The One-Time Inspection Program is credited for managing this aging
 
effect. The staff inquired as to the technical basis for concluding that the One-Time Inspection
 
Program is adequate to manage this aging effect for these material and environment
 
combinations for this system. By letter dated October 8, 2004, the applicant submitted its formal
 
response to the staff, stating that the air/gas components in the auxiliary boiler system were exposed to secondary quality water or steam that had been isolated by the layup of the auxiliary
 
boilers. The portions of the system that now contain air/gas are isolated and there is no
 
mechanism for introducing contaminants or additional oxygen. Since the portions of the auxiliary
 
boiler system exposed to air/gas were originally chemistry controlled, the potential for corrosion
 
is low. The One-Time Inspection Program will veri fy this by performing a sampling inspection. If corrosion is found to be present, additional inspections and corrective actions may be required
 
by the One-Time Inspection Program.
The staff concluded that the applicant's response is acceptable. The water to which these components were exposed was chemically treat ed, and the components are now isolated such that neither contaminants nor additional oxygen will be introduced into the air/gas environment.
Therefore, the potential for corrosion of these components is low. The one-time inspection will
 
verify that corrosion is not occurring. If corrosion is detected, additional inspections and
 
corrective actions will be taken.
Loss of Material due to Selective Leaching of Copper Alloy in a Treated Water Environment
.The applicant identified loss of material due to selective leaching for components constructed of
 
copper alloy in a treated water environment on their internal surface as an AERM. The 3-226 One-Time Inspection Program is credited for managing this aging effect. The staff inquired as to the technical basis for concluding that the One-Time Inspection Program is adequate to manage
 
this aging effect for this material and environment combination for components in this system.
 
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating
 
that the One-Time Inspection Program had been identified in error. The correct AMP for this
 
aging effect is the Selective Leaching of Materials Program.
The staff concluded that the applicant's response is acceptable since the Selective Leaching of Materials Program was developed specifically to address loss of material due to selective
 
leaching. The One-Time Inspection Program was incorrectly listed in Table 3.2.2.1 for this
 
component.
3.3.2.3.2  Fuel Oil System - Summary of Aging Management Evaluation - Table 3.3.2.2 The staff reviewed LRA Table 3.3.2.2, which summarizes the results of AMR evaluations for the fuel oil system component groups.
In LRA Table 3.3.2.2, the applicant states that pumps, piping, and fittings made from carbon and low-alloy steel in fuel oil experience no aging effects. Copper alloy in fuel oil is subjected to
 
loss of material due to MIC. The applicant also states that fittings made from copper alloy in
 
inside air experience no aging effects. For flexible hoses made from elastomer - rubber in fuel
 
oil (internal) subjected to elastomer degradation due to oxidation, the applicant proposes that
 
these be managed by the One-Time Inspection Progr am. Flexible hoses made from elastomer -
rubber in inside air may experience elastomer degradation due to ultraviolet radiation, and will
 
be managed by the Systems Monitoring Program.
LRA Section 3.3.2.2 states that components made from copper alloy and exposed to inside air (external environment) experience no AERMs and require no AMPs. In a general RAI, the staff
 
questioned whether the copper alloy components exposed to inside air would be subject to
 
aging effects. The staff found the applicant's assessment of the copper alloy components to be
 
acceptable, as discussed in SER Section 3.3.2.3.
The staff's review of LRA Section 3.3.2.2 identified areas in which additional information was necessary to complete the review of the applicant's results. The applicant responded to the
 
staff's RAI as discussed below.
In RAI 3.3.2.2-2, dated October 12, 2004, the staff noted that numerous line items In LRA Table 3.3.2.2 state that carbon and low-alloy steel components in fuel oil experience no AERMs
 
and require no AMPs. This is not consistent with the GALL Report or with industry experience.
 
Notes associated with these line items indicate that the AERMs identified in the GALL Report for
 
this material/environment combination are not applicable (Note I) for the following reasons: (1)
 
pitting, crevice, general, or galvanic corrosion are not concerns because there is no water
 
collection in these components (Note 5, applied to fittings, piping, pumps, restricting orifice, strainers, and tubing); (2) biofouling is not a concern (Note 7, applied to tanks); or (3) galvanic
 
corrosion is not a concern because there are no galvanic couples in the portions of the system
 
where water could accumulate and provide a conductor (applied to tanks). Adjacent line items in
 
LRA Table 3.3.2.2 for the same material, environment, and GALL reference state that the
 
components are subjected to loss of material due to MIC and credit the Fuel Oil Chemistry
 
Program and the One-Time Inspection Program for aging management. Therefore, the staff 3-227 requested the applicant to clarify the above AMR and whether the Fuel Oil Chemistry Program and the One-Time Inspection Program are credited for all carbon steel and low-alloy
 
components in the system.
In its response, by letter dated November 3, 2004, the applicant clarified that the AMR line items that state that carbon and low-alloy steel components in fuel oil experience no AERMs are there
 
to indicate that some potential aging mechanisms identified in the GALL Report are not
 
applicable. GALL Report, Volume 2, Section VII.G.8-a, lists the four aging mechanisms as
 
general, galvanic, pitting, and crevice corrosion, while the applicant's AMR determined that the
 
only aging mechanism applicable to these components (where there is no water accumulation)
 
is MIC. MIC forms the basis of the adjacent AMR line item. The applicant also clarified that the
 
Fuel Oil Chemistry Program and the One-Time Inspection Program are credited as aging managements programs for all carbon steel and low-alloy steel components in the fuel oil
 
system with a fuel oil internal environment.
The staff concurred with the applicant's assessment that MIC is the predominant aging effect for carbon and low-alloy steel in fuel oil where there is
 
no potential for water accumulation. The staff also noted that the inspections performed on this
 
system will identify the AERMs in the GALL Report, if they are present. Therefore, the staff
 
found that the applicant had identified the appropriate aging effects.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the above RAIs, the staff found the aging effects of the
 
above AMR items are consistent with industry ex perience for these combinations of materials and environments. The staff did not identify any omitted aging effects. Therefore, the staff found
 
that the applicant had identified the appropriate aging effects for the materials and environments
 
associated with the above components in the fuel oil system.
LRA Table 3.3.2.2 identifies the following AMPs for managing the aging effects described above: Fuel Oil Chemistry Program, One-Time Inspection Program, and the Systems Monitoring Program. The staff's detailed reviews of these AMPs are found in SER Sections 3.0.3.2.18, 3.0.3.1.7, and 3.0.3.3.1, respectively.
In RAI 3.3.2.2-1, dated October 12, 2004, the staff stated that LRA Section 3.3.2.2. implies that the one-time inspections will be limited to t he system locations where contaminants are expected to accumulate; however, AERMs (particularly MIC) are identified for a larger
 
population of components. Therefore, the staff requested the applicant to clarify the use of the
 
one-time inspections. In its response, by letter November 3, 2004, the applicant stated that the
 
Fuel Oil Chemistry Program and the One-Time Ins pection Program are credited as AMPs for all components in the fuel oil system with a fuel oil internal environment where aging effects were identified. These programs are being applied to all components with identified AERMs;
 
therefore, the staff found this acceptable.
For the flexible hoses made of elastomer (rubber) in a fuel oil environment, the LRA credits the One-Time Inspection Program to manage the aging effect of elastomer degradation due to
 
oxidation. The One-Time Inspection Program is typi cally used to verify that an aging effect is not occurring or when an aging effect is expected to occur slowly, such that the component
 
intended function can be maintained for the extended period of operation. For these same
 
hoses, the LRA credits the Systems Monito ring Program to manage the aging effect of elastomer degradation due to ultraviolet radiat ion. The Systems Monitoring Program provides for visual inspections of the hoses. The staff found the periodic inspections, combined with the 3-228 one-time inspection of the hose internal surface, adequate for managing the aging of the flexible hoses. Therefore, the staff found the management of these hoses to be acceptable.
The staff reviewed LRA Table 3.3.2.2, which summarized the results of AMR evaluations for the fuel oil system component groups. The applicant identified no aging effect or AMP for
 
components constructed of cast iron and cast iron alloy, as well as carbon or low-alloy steel in
 
an air/gas environment on their internal surface. During the onsite audit, the staff inquired as to
 
the technical justification for concluding that there are no aging effects for these
 
material/environment combinations for component s in this system. By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that components in the
 
fuel oil system are exposed to a fuel oil vapor environment. This f uel oil vapor environment protects the component surfaces and prevents internal corrosion.
The staff concluded that the applicant's determination of no AERMs for components in the fuel oil system in an air/gas environment on the inte rnal surface is acceptable since the components will be exposed to fuel oil vapor, which will protect the surfaces of the components from corrosion.
On the basis of its review of the information provided in the LRA and RAI responses, the staff found the applicant had identified appropriate AMPs for managing the aging effects of the above
 
fuel oil system components. In addition, the staff found the program descriptions in the UFSAR
 
supplement acceptable.
No Aging Effect or Aging Management Program Identified. The applicant identified no aging effect or AMP for components constructed of cast iron and cast iron alloy, as well as carbon or
 
low-alloy steel in an air/gas environment on their internal surface. During the onsite audit, the
 
staff inquired as to the technical justification for concluding that there are no aging effects for
 
these material/environment combinations fo r components in this system. By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that
 
components in the fuel oil system are exposed to a fuel oil vapor environment. This fuel oil vapor environment protects the component su rfaces and prevents internal corrosion.
The staff concluded that the applicant's determination of no AERMs for components in the fuel oil system in an air/gas environment on the inte rnal surface is acceptable since the components will be exposed to fuel oil vapor, which will protect the surfaces of the components from corrosion.
3.3.2.3.3  Residual Heat Removal Service Water System - Summary of Aging Management Evaluation - Table 3.3.2.3 The staff reviewed LRA Table 3.3.2.3, which summarizes the results of AMR evaluations for the RHRSW system component groups.
In LRA Table 3.3.2.3, the applicant identifies aging effect for the RHRSW system components within the scope of license renewal and subject to AMR. The AMR lists the components, materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line
 
items that do not rely on the GALL Report include the following: fittings, piping, and valves made
 
from aluminum alloy in an environment of tr eated water (internal) are subjected to crack initiation and growth due to SCC, and loss of material due to crevice and pitting corrosion, and 3-229 will be managed by the Chemistry Control Progr am and the One-Time Inspection Program.
Fittings, piping, and valves made from carbon and low-alloy steel in an environment of treated water (internal) are subject to loss of material due to crevice, general, and pitting corrosion.
 
Fittings made from polymer in environments of inside air (external) and treated water (internal) experience no AERMs and require no AMPs.
Through a staff teleconference follow up request dated February 11, 2005, the staff requested the applicant to provide additional clarification regarding the type of elastomer or polymer, its
 
environment, and justification that there are no AERMs for the elastomer or polymer
 
components. In its response, by letter dated March 11, 2005, the applicant clarified that the
 
polymer components in this system are Derlin (acetal) insulating couplings between dissimilar material threaded piping. Based on its review of the material data sheet for Derlin, the staff
 
concluded that the material is rated for continuous service in environmental conditions (e.g.,
temperature) significantly in excess of the c onditions in the RHRSW system. Therefore, the staff concurred with the applicant's evaluation that there are no AERMs for the polymer components
 
in this system.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the above RAIs, the staff found the aging effects of the
 
above AMR items are consistent with industry ex perience for these combinations of materials and environments. The staff did not identify any omitted aging effects. Therefore, the staff found
 
that the applicant had identified the appropriate aging effects for the materials and environments
 
associated with the above components in the RHRSW.
No Aging Effect or Aging Management Program Identified. The applicant identified no aging effect or AMP for components constructed of cast iron and cast iron alloy, as well as carbon or
 
low-alloy steel in an embedded/encased environment on their external surface. During the
 
onsite audit, the staff inquired as to the technical justification for concluding that there are no
 
aging effects for these material and environment combinations for components in this system.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating
 
that no aging effects are identified for embedded/encased components. If excessive corrosion
 
that could prevent the performance of the intended functions during the period of extended
 
operation was detected on the inside surface or outside surface in air environments adjacent to
 
the embedded/encased portions, corrective actions would be taken to restore the component, including the embedded/encased portions, if this was determined to be necessary.
The staff concluded that the applicant's determination of no AERMs for components in the RHRSW system in an embedded/encased environment is acceptable since exposure to a corrosive environment will be limited. Inspec tions will be performed on adjacent surfaces exposed to an air environment. If corrosion was detected on adjacent surfaces in an air
 
environment, corrective actions would be taken to restore the component, including the
 
embedded/encased portions, if this was determined to be necessary.
3.3.2.3.4  Raw Cooling Water System -
Summary of Aging Management Evaluation -
Table 3.3.2.4 The staff reviewed LRA Table 3.3.2.4, which summarizes the results of AMR evaluations for the raw cooling water system component groups.
3-230 In LRA Table 3.3.2.4, the applicant identifies aging effect for the raw cooling water system components within the scope of license renewal and subject to AMR. The AMR lists the
 
materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line
 
items that do not rely on the GALL Report include the following: fittings, tubing, and valves
 
made from copper alloy and exposed to inside air (external environment) experience no AERMs and require no AMPs; expansion joints made from elastomer exposed to inside air (external)
 
and raw water (internal) experience no AERMs and require no AMPs; fittings and piping made
 
from polymer in air/gas (internal) or insi de air (external) environments experience no AERMs and require no AMPs.
In the general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
In its response to the staff's informal request February 11, 2005, by letter dated March 11, 2005, the applicant clarified that the elastomer components are fabric reinforced expansion joints (Garlock Style 204) made from chlorobutyl/polyester. The coating cover reduces ultraviolet
 
radiation to negligible levels, the system temperature is low relative to the qualified temperature, and the elastomers are not exposed to significant radiation. Based on the above, the staff
 
concurred with the applicant's conclusion that there are no AERMs for the elastomer
 
components in this system.
With respect to the polymer components, by the letter dated March 11, 2005, the applicant clarified that the polymer components are molded plastic fittings and piping in air/gas and inside
 
air. The applicant stated that once the proper polymer, resistant to the environment, is chosen, there are no AERMs. The applicant further stated that industry guidance does not identify any
 
AERMs for this polymer and environment, but that the components would be included in the
 
Systems Monitoring Program to verify that ther e is no hardening or loss of material strength due to polymer degradation.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the above RAIs, the staff found the aging effects of the
 
above AMR items are consistent with industry ex perience for these combinations of materials and environments. The staff did not identify any omitted aging effects or the need for any AMPs for the above combinations of material and environment. Therefore, the staff found that the
 
applicant had identified the appropriate aging effects for the materials and environments
 
associated with the above components in the raw cooling water system.
3.3.2.3.5  Raw Service Water System -
Summary of Aging Management Evaluation -
Table 3.3.2.5 The staff reviewed LRA Table 3.3.2.5, which summarizes the results of AMR evaluations for the raw service water system component groups.
In LRA Table 3.3.2.4, the applicant identifies the aging effects of the service water system components within the scope of license renewal and subject to AMR. The AMR lists the
 
materials, environments, AERMs, and AMPs credited for managing the AERMs. The only AMR
 
line items that do not rely on the GALL Report are as follows: fittings and valves made from 3-231 copper alloy and exposed to inside air (external environment) experience no AERMs and require no AMPs.
In a general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.1.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the RAI, the staff found the aging effects of the above
 
AMR items are consistent with industry experience for these combinations of materials and
 
environments. The staff did not identify any omi tted aging effects or the need for any AMPs for the above combinations of material and environment. Therefore, the staff found that there is
 
reasonable assurance that the component intended functions will be maintained consistent with
 
the CLB for the period of extended operation, as required by 10 CFR 54.29(a).
3.3.2.3.6  High Pressure Fire Protection Syst em - Summary of Aging Management Evaluation -
Table 3.3.2.6 The staff reviewed LRA Table 3.3.2.6, which summarizes the results of AMR evaluations for the high pressure fire protection system component groups.
In LRA Section 3.3.2.1.6 and Table 3.3.2.6, the applicant identified the materials, environments, and AERMs. The materials identified include carbon steel, alloy steel, stainless steel, aluminum, cast iron, elastomers, glass, and copper alloys.
The applicant identified the environments to which these materials could be exposed as air and gas (wetted, ambient and dry), raw water (well water), treated water and AFFF and includes
 
environments inside, outside, and buried. The applicant identified loss of material (from
 
corrosion or leaching) and degradation (UV degradation of elastomers) as the aging effects
 
associated with the fire water system.
Staff Evaluation. The staff reviewed the LRA to determine whether the applicant had demonstrated that it would adequately manage the effects of aging for the fire protection system
 
during the period of extended operation, as required by the regulations that govern LRA. The
 
staff also reviewed LRA Sections of 3.3.2.6 and Table 3.3.2.6 for completeness and consistency
 
with the GALL Report and industry experience.
On the basis of its review of the LRA, the staff found that the aging effects resulting from exposure of the fire water system com ponents to the environments described in LRA Table 3.3.2.6 are consistent with the GALL Report and with industry experience for these
 
material-environment combinations. Therefore, the staff found that the applicant identified the
 
applicable aging effects and associated AMPs and that they are appropriate for the combination
 
of materials and environments listed.
3.3.2.3.7  Potable Water System - Summary of Aging Management Evaluation - Table 3.3.2.7
 
The staff reviewed LRA Table 3.3.2.7, which summarizes the results of AMR evaluations for the potable water system component groups.
3-232 In LRA Table 3.3.2.7, the applicant stated the aging effects of the potable water system components within the scope of license renewal and subject to AMR. The AMR lists the
 
materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line
 
items that do not rely on the GALL Report include the following: fittings, tubing, and valves
 
made from copper alloy and exposed to inside air, which experience no AERMs and require no
 
AMPs; fittings and piping made from carbon and low-alloy steel in raw water for loss of material
 
due to galvanic, general, crevice and pitting co rrosion, which will be managed by the One-Time Inspection Program. LRA Section 2.3.3.7 clarifies that the raw water is potable water supplied
 
by the city of Athens, Alabama. LRA Table 3.3.2.7 notes clarify that the water is chlorinated to
 
prevent the growth of microorganisms, such that biofouling and MIC are not expected, but that
 
chlorination introduces the possibility of SCC for the stainless steel components. For valves
 
made from carbon and low-alloy steel in raw water, loss of material due to general, crevice, and
 
pitting corrosion will be managed by the One-Time Inspection Program. For fittings made from cast iron and cast iron alloy in raw water, loss of material due to general, crevice, pitting, and
 
galvanic corrosion will be managed by the One-Time Inspection Program. For valves made from cast iron and cast iron alloy (gray) in raw water, loss of material due to general, crevice, pitting, and galvanic corrosion will be managed by the One-Time Inspection Program. For fittings and valves made from stainless steel in raw water, crack initiation and growth due to SCC will be
 
managed by the One-Time Inspection Program.
For fittings, tubing, and valves made from copper alloy in raw water, loss of material due to crevice and pitting corrosion will be managed
 
by the One-Time Inspection Program.
In general RAI 3.3.2.2-1 the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
The staff also noted that for the carbon and low-alloy exposed to raw water, galvanic corrosion is identified as a potential aging effect for the fittings and piping, but not for the valves. In its
 
March 11, 2005, response to the staff's informal request February 11, 2005, the applicant
 
clarified that galvanic corrosion is only applicable when the component is in contact with a more
 
cathodic material, and that the valves in question are not connected to more cathodic materials.
 
The staff found this explanation reasonable and acceptable.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the RAI, the staff found the aging effects of the above
 
AMR items are consistent with industry experience for these combinations of materials and
 
environments. The staff did not identify any omitted aging effects. Therefore, the staff found that
 
the applicant had identified the appropriate aging effects for the materials and environments
 
associated with the above components in the potable water system.
Loss of Material due to Corrosion for Copper Alloys in a Raw Water Environment. The applicant identified loss of material due to crevice and pitting corrosion for components constructed of
 
copper alloy and stainless steel in a raw water environment on their internal surface as an
 
AERM. The One-Time Inspection Program is credited for managing this aging effect. The staff
 
inquired as to the technical basis for concluding that the One-Time Inspection Program is
 
adequate to manage this aging effect for these material and environment combinations for
 
components in this system. By letter dated Oct ober 8, 2004, the applicant submitted its formal response to the staff, stating that LRA Table 3.3.2.7 for the potable water system evaluates the
 
potable (city) water as a raw water source. The ac tual chemistry is much milder than expected 3-233 for raw water. Therefore, loss of material affecting component operation during the period of extended operation is not expected. The One-Time Inspection Program will verify this by performing a sampling inspection. If corrosion is found to be present, additional inspections and
 
corrective actions may be required by the One-Time Inspection Program.
The staff concluded that the applicant's response is acceptable since raw water for this system is actually potable water, which has a milder chemistry. Therefore, the potential for corrosion is
 
low. The One-Time Inspection Program will verify that corrosion is not occurring. If corrosion is
 
detected, additional inspections and corrective actions will be taken.
3.3.2.3.8  Ventilation System - Summary of Aging Management Evaluation - Table 3.3.2.8 The staff reviewed LRA Table 3.3.2.8, which summarizes the results of AMR evaluations for the ventilation system component groups.
In LRA Table 2.3.3-8, the applicant lists individual system components within the scope of license renewal and subject to AMR. The AMR lis ts the components, materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line items that do not rely on
 
the GALL Report include the following: ducting made from carbon and low-alloy steel in air/gas (internal) and elastomer - rubber and silicone rubber in air/gas (internal) experience no AERMs
 
and require no AMPs. Elastomer - rubber and silicone rubber in air/gas (external) experience
 
elastomer degradation due to ultraviolet radiation.
In RAI 3.3.2.1.8-1, dated December 10, 2004, the staff requested additional information regarding the applicant's claim in LRA Table 3.3.2.8 that the carbon and low-alloy steel
 
ductwork experiences no aging effects. The staff noted that adjacent entries in LRA
 
Table 3.3.2.8 for the same material, environment, and GALL Report reference identify a loss of
 
material due to general corrosion. It appeared to the staff that the applicant takes exception to
 
the GALL Report's identification of crevice corrosion, pitting corrosion, and MIC as not
 
applicable while general corrosion is applicable. In its response, by letter November 3, 2004, the
 
applicant confirmed that the AMR was intended to state that the applicant took exception to the
 
GALL-identified AERMs of crevice corrosion, pitting corrosion, and MIC, because the GALL
 
identifies these AERMs for drip pans and drain lines, which are typically wet. Instead, the
 
applicant identifies general corrosion (in adjacent line items) and credits the One-Time
 
Inspection Program. The staff found the applicant's response acceptable because the applicant
 
stated that the ducting is not expected to be wetted. The staff also found that the one-time
 
inspection will be adequate to identify a loss of material in the ducting.
The technical staff also questioned the AMR items related to elastomer - rubber and silicone rubber ductwork in air/gas and inside air. For these material/environment combinations, the
 
applicant claims that there are no AERMs based on industry guidance. The degradation of
 
elastomers depends on environmental factors such as the temperature, radiation levels, and
 
presence of aggressive chemicals. Degradation c an also be caused by wear (for items such as seals and vibration dampers). The staff asked the applicant to provide additional information on
 
the above factors to justify that there are no AERMs for the elastomers, or to provide aging
 
management for the elastomer components in the ductwork. In its response dated November 3, 2004, the applicant clarified that the elastomer degradation due to ultraviolet radiation is
 
identified (in adjacent LRA Table 3.3.2.8 AMR items) and managed by t he Systems Monitoring Program. The applicant did not identify elastomer degradation due to thermal exposure or 3-234 ionizing radiation because the components in question remain below the thresholds for significant degradation from these factors. Based on the above, the staff found that the
 
applicant had adequately addressed the concerns; therefore, the RAI 3.3.2.1.8-1 is resolved.
On the basis of its review of the information provided in the LRA (and the additional information included in the applicant's response to the above RAI, the staff found the aging effects of the
 
above ventilation system component types that are not addressed by the GALL Report are consistent with industry experience for these combinations of materials and environments. The
 
staff did not identify any omitted aging effects. Therefore, the staff found that the applicant had
 
identified the appropriate aging effects for the materials and environments associated with the
 
above components in the ventilation system.
On the basis of its review, the staff concluded that the applicant had adequately identified the aging effects for the ventilation system component s that are not addressed by the GALL Report so that there is reasonable assurance that the intended functions will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.29(a).
3.3.2.3.9  Heating, Ventilation, and Air C onditioning System - Summary of Aging Management Evaluation - Table 3.3.2.9 The staff reviewed LRA Table 3.3.2.9, which summarizes the results of AMR evaluations for the HVAC system component groups.
In LRA Table 2.3.3.9, the applicant lists individual system components within the scope of license renewal and subject to AMR. The AMR lis ts the components, materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line items that do not rely on
 
the GALL Report include the following:
Components in raw water (potable): for the carbon and low-alloy steel components (fittings, heat exchangers, strainers, tanks and valves), the applicant identifies loss of material due to general, crevice, pitting, and galvanic corrosion, and credits the One-Time Inspection Program. For the
 
cast iron and cast iron alloy components (fittings, heat exchangers, pumps, and valves), the
 
applicant identifies loss of material due to general, crevice, pitting, and galvanic corrosion, and
 
credits the One-Time Inspection Program. In addition, for the cast iron and cast iron alloy heat
 
exchangers, the applicant also identifies selective leaching, and credits the Selective Leaching
 
of Materials Program (as clarified by letter dated March 11, 2005). For the stainless steel
 
components (fittings, flexible connectors, heat exchangers, piping and valves), the applicant
 
identifies crack initiation and growth due to SCC and loss of material due to crevice and pitting
 
corrosion, and credits the One-Time Inspection Program. For the copper alloy components (fittings, heat exchangers, tubing, and valves), the applicant identifies loss of material due to
 
crevice, galvanic, and pitting corrosion, and credits the One-Time Inspection Program.
Components in treated water: for the carbon and low-alloy steel components (fittings, heat exchangers, piping, strainers, tanks and valves), the applicant identifies galvanic corrosion and
 
credits the Closed-Cycle Cooling Water System Program. For the stainless steel components (fittings, flexible connectors, piping, pumps, strainers, tubine and valves), the applicant identifies
 
crack initiation and growth due to SCC and loss of material due to crevice and pitting corrosion, and credits the Closed-Cycle Cooling Water System Program.
3-235 Components in raw water: for carbon steel and low-alloy steel piping, the applicant identifies loss of material due to general, crevice, pitting, and galvanic corrosion, and credits the
 
One-Time Inspection Program. For stainless steel heat exchangers, the applicant identifies
 
crack initiation and growth due to SCC and loss of material due to crevice and pitting corrosion, and credits the One-Time Inspection Program.
In addition to the above aging effects, the applicant identifies loss of heat transfer due to particulate fouling, and credits the One-Time Inspection Program, for heat exchanger
 
components made from aluminum alloy, copper allo y, and stainless steel in raw water (potable), raw water, and air/gas environments.
The applicant identified no aging effects and, consequently, no AMPs, for polymer components (fittings, flexible connectors, tubing and valves) in air/gas (internal) and inside air (external),
elastomer ductwork and flexible connectors in air/gas (internal) or inside air (external), and
 
copper alloy components in inside air (external).
In general RAI 3.3.2.2-1 the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
The staff asked for additional information related to elastomer components, since the applicant determined that there are no AERMs based on industry guidance. The degradation of
 
elastomers depends on the environmental factors such as the temperature, radiation levels, and
 
presence of aggressive chemicals (aggressive chem icals are not anticipated for this system). In its response to the staff's informal request February 11, 2005, by letter dated March 11, 2005, the applicant demonstrated that the temperature and radiation levels remain below the
 
thresholds for which there is significant aging of the silicon and neoprene components, the
 
neoprene coated glass material (Dupont's Ventglass). Therefore, the staff concurred with the
 
applicant's assessment.
With respect to the polymer components, by letter dated March 11, 2005, the applicant clarified that the polymer components are molded plastic (valves), molded nylon (fittings), hypalon
 
coated nylon (flexible connectors), and Nycoa Nylon 589 (tubing) in air/gas and inside air. The
 
applicant stated that once the proper polymer, resistant to the environment, is chosen, there are
 
no AERMs. The applicant further stated that industry guidance does not identify any AERMs for
 
these polymers and environments, but that t he components would be included in the Systems Monitoring Program to verify that there is no hardening or loss of material strength due to
 
polymer degradation.
In RAI 3.3.2.1.9-2, dated October 12, 2004, the staff stated that in Table 3.3.2.1.9 the applicant claimed that there are no AERMs for this material environment combination of copper-alloy heat
 
exchanger in inside air (external). Condensation in the heat exchangers could lead to aging
 
effects, and there is the potential for loss of heat transfer by such mechanisms as particulate
 
fouling. In its November 3, 2004, response, the applicant clarified that the coils are for cooling
 
freon, so that there is no condensation. Also, due to the design of the cooling coils (no fins),
they are not susceptible to particulate fouling. Since there will be no condensation on the coils
 
and since the design is not susceptible to particulate fouling, the staff agreed with the
 
applicant's assessment. Therefore, the staff found the applicant's response acceptable and
 
RAI 3.3.2.1.9-2 is resolved.
3-236 On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the above RAIs, the staff found the aging effects of the
 
above heating, ventilation, and air conditioning sy stem component types that are not addressed by the GALL Report are consistent with industry experience for these combinations of materials and environments. The staff did not identify any omitted aging effects. Therefore, the staff found
 
that the applicant had identified the appropriate aging effects for the materials and environments
 
associated with the above components in the heat ing, ventilation, and air conditioning system.
Crack Initiation and Growth due to SCC for Copper Alloys and Stainless Steel in Raw Water Environments. The applicant identified crack initiation and growth due to SCC as an AERM for heat exchangers constructed of stainless steel in a raw water environment. The applicant
 
credited the One-Time Inspection Program to manage this aging effect. The staff inquired as to
 
the technical basis for identifying this aging effect for this material and environment
 
combination. By letter dated October 8, 2004, the applicant submitted its formal response to the
 
staff, stating that, upon further review, the cracking aging effect was inappropriately identified for
 
the raw water environment and should be deleted from the Table 3.3.2.9 entry for these
 
components.
The staff concluded that the applicant's response is acceptable for this material and environment combination since the conditions for SCC are not expected to be present in the
 
environment identified.
Crack Initiation and Growth due to SCC for Stainless Steel and Cast Austenitic Stainless Steel in Treated Water Environments. The applicant identified crack initiation and growth due to SCC as an AERM for fittings, flexible connectors, pipi ng, tubing and valves constructed of stainless steel in a treated water environment. The applicant credited the Closed-Cycle Cooling Water
 
System Program to manage this aging effect. During the onsite audit, the staff inquired as to
 
how the Closed-Cycle Cooling Water System Progr am would detect cracking prior to the loss of intended function for these components. By letter dated October 8, 2004, the applicant
 
submitted its formal response to the staff, stating that, upon further review, the cracking aging
 
effect is unnecessary for these components. In addition, components were identified with
 
cracking of stainless steel in a raw water environment in potable water, and heating, ventilation
 
systems, and air conditioning. The applicant determined that this cracking aging effect is also
 
unnecessary.
The staff concluded that the applicant's response is acceptable for this material and environment combination since the conditions c onducive to SCC are not present in the system identified.
Loss of Material Due to Corrosion for Cast Iron and Carbon/Low Alloy Steels in an Air/Gas Environment. The applicant identified loss of material due to crevice, galvanic, general, and pitting corrosion as an AERM for heat exchangers constructed of cast iron and cast iron alloy, as well as heaters and heat exchangers constructed of carbon or low-alloy steel in an air/gas
 
environment on their internal surface. The One-Time Inspection Program is credited for
 
managing this aging effect. During the onsite audit, the staff inquired as to the technical basis
 
for concluding that the One-Time Inspection Program is adequate to manage this aging effect
 
for components with these material and environment combinations in this system. By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the
 
components in the heating, ventilation, and air conditioning system located in an air/gas 3-237 environment were exposed to heated and cooled circulated air. Loss of material is consistent with the GALL Report, although the GALL Report identifies only general corrosion. Based on the
 
potential for water accumulation on or in the area of the cooling coils, additional potential aging
 
mechanisms were identified. Actual experience based on a review of work orders and PERs
 
demonstrates that loss of material has not been an issue for these components within this
 
system. In particular, no instances of pitting, crev ice, or galvanic corrosion were identified in this review. The One-Time Inspection Program will verify this by performing a sampling inspection. If corrosion is found to be present, additional inspections and corrective actions may be required
 
by the One-Time Inspection Program.
The staff concluded that the applicant's response is acceptable since these components are normally exposed to heated and cooled air and the potential for loss of material due to crevice, galvanic, and pitting corrosion is low. Loss of material due to crevice, galvanic, and pitting
 
corrosion of these components was included since there is the potential for water accumulation
 
near them; however, a review of past operating experience confirms that this aging effect has
 
not been a problem. The One-Time Inspection Program will verify that loss of material is not
 
occurring. If loss of material is detected, additional inspections and corrective actions will be
 
taken.Fouling Product Buildup due to Particulate for Copper Alloy and Stainless Steel in an Air/Gas Environment. The applicant identified fouling product buildup due to particulate as an AERM for heat exchangers constructed of copper alloy and stainless steel in an air/gas environment on
 
their internal surface. The One-Time Inspection Program is credited for managing this aging
 
effect. During the onsite audit, the staff inquired as to the technical basis for concluding that the
 
One-Time Inspection Program is adequate to manage this aging effect for these material and
 
environment combinations for this system. By letter dated October 8, 2004, the applicant
 
submitted its formal response to the staff, stating that the air/gas environment to which the
 
cooling coils are exposed is heated and cooled circulated air. The actual plant experience
 
based on a review of work orders and problem reports demonstrates that fouling has not been
 
an issue with this system. The One-Time Inspec tion Program will verify this by performing a sampling inspection. If fouling is found to be present, additional inspections and corrective
 
actions may be required by the One-Time Inspection Program.
The staff concluded that the applicant's response is acceptable. These components are normally exposed to heated and cooled air and the potential for fouling due to particulate is low.
 
A review of past operating experience confirms that this aging effect has not been a problem, and the One-Time Inspection Program will verify that fouling is not occurring. If fouling is
 
detected, additional inspections and corrective actions will be taken.
Fouling Product Buildup due to Particulate for Stainless Steel in a Raw Water Environment. The applicant identified fouling product buildup due to particulate as an AERM for heat
 
exchangers constructed of stainless steel in a raw water environment on their internal surface.
 
The One-Time Inspection Program is credited for managing this aging effect. During the onsite
 
audit, the staff inquired as to the technical basis for concluding that the One-Time Inspection
 
Program is adequate to manage this aging effect. By letter dated October 8, 2004, the applicant
 
submitted its formal response to the staff, stating that the raw water referred to in this line item
 
is actually potable (city) water. The chemistry of the potable water is much milder than expected
 
for raw water. Therefore, loss of material and fouling potentially affecting component operability
 
during the period of extended operation is not ex pected. The One-Time Inspection Program will 3-238 verify this by performing a sampling inspection. If corrosion or fouling is found to be present, additional inspections and corrective actions ma y be required by the One-Time Inspection Program. The staff concluded that the applicant's response is acceptable since the raw water referred to in this line item is actually potable (city) water. The chemistry of the potable water is much
 
milder than expected for raw water. Therefore, loss of material and fouling potentially affecting
 
component operability during the period of extended operation is not expected. The One-Time
 
Inspection Program will verify this by performing a sampling inspection.
No Aging Effect or Aging Management Program Identified.
The applicant identified no aging effect or AMP for heat exchangers constructed of aluminum alloy and copper alloy in an outside
 
air environment on the external surface. During the onsite audit, the staff inquired as to the
 
technical justification for concluding that there are no aging effects for this material/environment
 
combination for this system. By letter dated October 8, 2004, the applicant submitted its formal
 
response to the staff, stating that the cooling coils identified in an outside environment are in the
 
Freon cycle and the air flow over the coils is to cool the Freon. Therefore, condensation on the
 
coils will not occur and loss of material is not identified as an aging mechanism requiring
 
management for the period of extended operation. Air side fouling of cooling coils that have no
 
condensation mechanism is only a problem for fin type heat exchangers. Therefore, fouling is
 
not identified as an aging mechanism requiring management for the period of extended
 
operation.
The staff concluded that the applicant's response is acceptable since these components are cooling coils exposed to air flow on the outside surface. The air flow is to cool Freon inside the
 
coils; therefore, the air will be heated and condensation will not occur on these components.
 
The applicant also identified no aging effect or AMP for heat exchangers constructed of copper
 
alloy in an air/gas environment on their internal surface. During the onsite audit, the staff
 
inquired as to the technical justification for concluding that there are no aging effects for these
 
material and environment combinations for components in this system. By letter dated October 8, 2004, the applicant submitted its formal response to the staff onsite audit questions
 
that Table 3.3.2.9, rows 131 and 132 are referring to the Freon side of the cooling coil and
 
correctly identify no aging effects. The material should reference Freon in the materials
 
description. These items are for the external surface of cooling coils and correctly identify loss
 
of material.
The staff concluded that the applicant's response is acceptable since the components will be exposed to Freon, which is not a corrosive environment for copper alloys; and also concurred
 
with the corrections to Table 3.3.2.9, rows 131 and 132 3.3.2.3.10  Control Air System - Summary of Aging Management Evaluation - Table 3.3.2.10 The staff reviewed LRA Table 3.3.2.10, which summarizes the results of AMR evaluations for the control air system component groups.
In LRA Table 3.3.2.10, the applicant identifies the aging effects of the control air system components within the scope of license renewal and subject to AMR. The AMR lists the
 
materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line
 
items that do not rely on the GALL Report include the following: for fittings made from carbon 3-239 and low-alloy steel in inside air, the applicant identifies loss of material due to general corrosion and credits the Systems Monitoring Program.
For components (heat exchangers, piping, and valves) made from carbon and low-alloy steel in treated water, the applicant identifies loss of
 
material due to general, crevice, pitting, and galvanic corrosion, and credits the Closed-Cycle
 
Cooling Water System Program. Fittings, t ubing, and valves made from copper alloy and exposed to inside air (external environment) experience no AERMs and require no AMPs.
In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the above RAIs, the staff found the aging effects of the
 
above control air system component types that are not addressed by the GALL Report are consistent with industry experience for these combinations of materials and environments. The
 
staff did not identify any omitted aging effects. Therefore, the staff found that the applicant had
 
identified the appropriate aging effects for the materials and environments associated with the
 
above components in the control air system.
3.3.2.3.11  Service Air System - Summary of Aging Management Evaluation - Table 3.3.2.11 The staff reviewed LRA Table 3.3.2.11, which summarizes the results of AMR evaluations for the service air system component groups.
In LRA Section 3.3.2.11 and Table 3.3.2.11, the applicant identified the materials, environments, and AERMs. The materials identified include carbon steel, alloy steel, stainless
 
steel, cast iron, and cast iron alloy. The applicant identified the environments to which these
 
materials could be exposed as air gas and inside air. The applicant identified loss of material
 
and loss of bolting function due to general corrosion.
The staff reviewed the LRA to determine whether the applicant had demonstrated that it would adequately manage the effects of aging for the serv ice air system during the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff reviewed LRA Section 3.3.2.11 and
 
Table 3.3.2.11 for completeness and consistency with the GALL Report and industry
 
experience.
The staff found that the applicant demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.12  CO 2 System - Summary of Aging Management Evaluation - Table 3.3.2.12 In Section 3.3.2.12 and LRA Table 3.3.2.12, the applicant identified the materials, environments, and AMR. The materials identified include carbon steel, alloy steel, stainless
 
steel, aluminum, cast iron, elastomers, glass, and copper alloys. The applicant identified the
 
environments to which these materials could be exposed as inside air and gas. The applicant
 
identified loss of material from corrosion as the aging effect associated with the CO 2 system components.
3-240 The staff reviewed the LRA to determine whether the applicant had demonstrated that it would adequately manage the effects of aging for the CO 2 system during the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff reviewed LRA Section 3.3.2.12 and
 
Table 3.3.2.12 for completeness and consistency with the GALL Report and industry
 
experience.
The staff found that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.3.13  Station Drainage System - Summary of Aging Management Evaluation -
 
Table 3.3.2.13 The staff reviewed LRA Table 3.3.2.13, which summarizes the results of AMR evaluations for the station drainage system component groups.
In LRA Table 3.3.2.13, the applicant identifies the aging effects of the station drainage system components within the scope of license renewal and subject to AMR. The AMR lists the
 
materials, environments, AERMs, and AMPs credited for managing the AERMs. The only AMR
 
that does not rely on the GALL Report is as follows: valves made from copper alloy and
 
exposed to inside air (external environment) experience no AERMs and require no AMPs.
In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
On the basis of its review of the information provided in the LRA and the applicant's November 3, 2004, response to the staff's RAI, the staff found the applicant's assessment
 
consistent with industry experience for this combination of material and environment. The staff
 
did not identify any omitted aging effects or the need for any AMPs for this combination of
 
material and environment. Therefore, the staff found that there is reasonable assurance that the
 
intended functions of the station drainage syst em valves made from copper alloy and exposed to inside air will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.29(a).
3.3.2.3.14  Sampling and Water Quality System
- Summary of Aging Management Evaluation -
Table 3.3.2.14 The staff reviewed LRA Table 3.3.2.14, which summarizes the results of AMR evaluations for the sampling and water quality system component groups.
In LRA Table 3.3.2.14, the applicant identified the aging effects of the sampling and water quality system components within the scope of license renewal and subject to AMR. The AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs. The
 
AMR line items that do not rely on the GALL Report include the following: fittings, heat
 
exchangers, tubing, and valves made from copper alloy and exposed to inside air (external
 
environment) experience no AERMs and require no AMPs. Polymer components (fittings, strainers, tubing, and valves) exposed to air/gas, inside air, and treated water experience no 3-241 AERMs and require no AMPs. Panel (Open sample panel) made from carbon and low-alloy steel in inside air (external) is subject to loss of material due to general corrosion.
In general RAI 3.3.2.1-1 the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
With respect to the polymer components, in its response to the staff's informal request of February 11, 2005, by letter dated March 11, 2005, the applicant clarified that the polymer
 
components are teflon fittings in treated water, air/gas, and inside air, polymer strainers in
 
treated water and inside air, and polymer tubing and valves in treated water, air/gas, and inside
 
air environments. The applicant stated that once the proper polymer, resistant to the
 
environment, is chosen, there are no AERMs. The applicant further stated that industry
 
guidance does not identify any AERMs for this polymer and environment, but that the
 
components would be included in the Systems Monito ring Program to verify that there is no hardening or loss of material strength due to polymer degradation.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the above RAIs, the staff found the aging effects of the
 
above AMR items are consistent with industry ex perience for these combinations of materials and environments. The staff did not identify any omitted aging effects or the need for any AMPs for the above combinations of material and environment. Therefore, the staff found that the
 
applicant had identified the appropriate aging effects for the materials and environments
 
associated with the above components in the sampling and water quality system.
3.3.2.3.15  Building Heat System - Summary of Aging Management Evaluation - Table 3.3.2.15 The staff reviewed LRA Table 3.3.2.15, which summarizes the results of AMR evaluations for the building heat system component groups.
In LRA Table 3.3.2.15, the applicant identifies the aging effects of the building heat system components within the scope of license renewal and subject to AMR. The AMR lists the
 
materials, environments, AERMs, and AMPs credited for managing the AERMs. The only AMR
 
that does not rely on the GALL Report is as follows: heaters made from copper alloy and
 
exposed to inside air (external environment) experience no AERMs and require no AMPs.
In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.1.
On the basis of its review of the information provided in the LRA, the staff found the applicant's assessment consistent with industry experience for this combination of material and
 
environment. The staff did not identify any omitt ed aging effects or the need for any AMPs for this combination of material and environment. Therefore, the staff found that there is reasonable
 
assurance that the intended functions of t he above building heat system components will be maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.29(a).
3-242 3.3.2.3.16  Raw Water Chemical Treatm ent System - Summary of Aging Management Evaluation - Table 3.3.2.16 The staff reviewed LRA Table 3.3.2.16, which summarizes the results of AMR evaluations for the raw water chemical treatment system component groups.
In LRA Table 3.3.2.16, the applicant identifies the aging effects of the raw water chemical treatment system components within the scope of license renewal and subject to AMR. The AMR lists the components, materials, envir onments, AERMs, and AMPs credited for managing the AERMs. The AMR line items that do not rely on the GALL Report include the following:
 
nickel alloy components (fittings, piping, and restricting orifice) exposed to raw water experience
 
loss of material due to biofouling, MIC, crevice and pitting corrosion, and are managed by the
 
One-Time Inspection Program, while nickel alloy components (fittings, piping, and restricting
 
orifice) exposed to outside air experience no AERMs and require no AMPs.
On the basis of its review of the information provided in the LRA, the staff found the aging effects of the above raw water chemical treat ment system AMR items are consistent with industry experience for these combinations of materials and environments. The staff did not
 
identify any omitted aging effects. Therefore, the staff found that the applicant identified the
 
appropriate aging effects for the materials and environments associated with the above
 
components in the raw water chemical treatment system.
Loss of Material due to Biofouling, MIC, Crevice and Pitting Corrosion for Nickel Alloys in a Raw Water Environment. The applicant identified loss of material due to biofouling, MIC, crevice and pitting corrosion for components constructed of nickel alloy in a raw water environment on their
 
internal surface as an AERM. The One-Time Inspection Program is credited for managing this
 
aging effect. During the onsite audit the staff inquired as to the technical basis for concluding
 
that the One-Time Inspection Program is adequate to manage this aging effect for this
 
material/environment combination for components in this system. By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the raw water referred
 
to in this line item is a diluted raw water chemical treatment solution. The diluted chemicals in
 
these nickel alloy components minimize any aging effects that potentially affect component
 
operability during the period of extended operation. If corrosion is found to be present, additional inspections and corrective actions ma y be required by the One-Time Inspection Program. The staff concluded that the applicant's response is acceptable since the raw water referred to in this line item is a diluted raw water chemical treatment solution. The diluted chemicals in
 
these nickel alloy components minimize any aging effects that potentially affect component
 
operability during the period of extended operation.
No Aging Effect or Aging Management Program Identified. The applicant identified no aging effect or AMP for fittings, piping, and valves constructed of polymer with a raw water
 
environment on the internal surface. During the onsite audit, the staff inquired as to the
 
technical justification for concluding that there are no aging effects for this material/environment
 
combination for this system. By letter dated October 8, 2004, the applicant submitted its formal
 
response to the staff, stating that the polymer referred to in Table 3.3.2.16 is the internal surface
 
of polypropylene-lined carbon steel components. The LRA does not credit the lining for
 
prevention of corrosion and this material/environment combination should be deleted.
3-243 The staff found that the applicant's response is acceptable, because the LRA does not credit the lining for prevention of corrosion on the internal surface, and also concurred with the
 
correction to LRA Table 3.3.2.16 to delete this material/environment combination.
3.3.2.3.17  Demineralizer Backwash Air System
- Summary of Aging Management Evaluation -
Table 3.3.2.17 The staff reviewed LRA Table 3.3.2.17, which summarizes the results of AMR evaluations for the demineralizer backwash air system component groups.
In LRA Table 3.3.2.17, the applicant identifies the aging effects of the demineralizer backwash air system components within the scope of lic ense renewal and subject to AMR. The AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs. The only
 
AMR that does not rely on the GALL Report is as follows: traps and valves made from copper alloy and exposed to inside air (external environment) experience no AERMs and require no
 
AMPs. Traps made from copper alloy and exposed to air/gas (internal)-pooled moisture
 
experience loss of material due to selective leaching.
In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
LRA Table 3.3.2.17 identifies the Selective Leaching of Materials Program for managing the aging effects described above.
The staff's detailed review of this AMP is found in SER Section 3.0.3.1.8.
 
On the basis of its review of the information provided in the LRA, the staff found the applicant's assessment consistent with industry experience for this combination of material and
 
environment. The staff did not identify any omitt ed aging effects or the need for any AMPs for this combination of material and environment. Therefore, the staff found that there is reasonable
 
assurance that the intended functions of the above demineralizer backwash air system
 
components will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.29(a).
3.3.2.3.18  Standby Liquid Control System
- Summary of Aging Management Evaluation -
Table 3.3.2.18 The staff reviewed LRA Table 3.3.2.18, which summarizes the results of AMR evaluations for the standby liquid control system component groups.
In LRA Table 3.3.2.18, the applicant identified the aging effects of the standby liquid control system components within the scope of license r enewal and subject to AMR. The AMR lists the components, materials, environments, AERMs , and AMPs credited for managing the AERMs.
The AMR line items that do not rely on the GALL Report include the following: polymer (Derlin) fittings exposed to inside air and treated water experience no aging effects and require no aging
 
management. Fittings made of carbon and low-alloy steel and exposed to air/gas (internal)
 
experience loss of material due to general corrosion.
3-244 In its response to the staff's informal request February 11, 2005, by letter dated March 11, 2005, the applicant stated that the Derlin is used as insulating flanges to prevent galvanic corrosion.
 
Based on its review of industry experience, the applicant determined that there are no AERMs
 
for Derlin in this application. Based on its review of the standby liquid control system and the
 
material property data sheet for Derlin, the staff concurred with the applicant's assessment.
LRA Table 3.3.2.18 identifies the One-Time Inspection Program for managing the aging effects described above.
The staff's detailed review of this AMP is found in SER Section 3.0.3.1.7.
 
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the above RAI, the staff found the aging effects of the
 
above AMR items are consistent with industry ex perience for these combinations of materials and environments. The staff did not identify any omitted aging effects or the need for any AMPs for the above combinations of material and environment. Therefore, the staff found that there is
 
reasonable assurance that the component intended functions will be maintained consistent with
 
the CLB for the period of extended operation, as required by 10 CFR 54.29(a).
3.3.2.3.19  Off-Gas System - Summary of Aging Management Evaluation - Table 3.3.2.19 The staff reviewed LRA Table 3.3.2.19, which summarizes the results of AMR evaluations for the off-gas system component groups.
In LRA Table 3.3.2.19, the applicant identified the aging effects of the off-gas system components within the scope of license renewal and subject to AMR. The AMR lists the
 
materials, environments, AERMs, and AMPs credited for managing the AERMs. The only AMR
 
that does not rely on the GALL Report is as follows: fittings made from copper alloy and
 
exposed to inside air (external environment) experience no AERMs and require no AMPs.
Valves made of carbon and low-alloy steel in air/gas (internal) and inside air (external) are
 
subject to loss of material due to general corrosion.
In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
LRA Table 3.3.2.19 identifies the following AMPs for managing the aging effects described above: One-Time Inspection Program and Syst ems Monitoring Program. The staff's detailed review of these AMPs is found in SER Sections 3.0.3.1.7 and 3.0.3.3.1.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the above RAIs, the staff found the aging effects of the
 
above AMR items are consistent with industry ex perience for these combinations of materials and environments. The staff did not identify any omitted aging effects or the need for any AMPs for the above combinations of material and environment. Therefore, the staff found that there is
 
reasonable assurance that the component intended functions will be maintained consistent with
 
the CLB for the period of extended operation, as required by 10 CFR 54.29(a).
3-245 3.3.2.3.20  Emergency Equipment Cooling Wa ter System - Summary of Aging Management Evaluation - Table 3.3.2.20 The staff reviewed LRA Table 3.3.2.20, which summarizes the results of AMR evaluations for the emergency equipment cooling water system component groups.
In LRA Table 3.3.2.20, the applicant identifies the aging effects of the emergency equipment cooling water system components within the scope of license renewal and subject to AMR. The
 
AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs.
 
The AMR line items that do not rely on the GALL Report include the following: fittings, heat
 
exchangers, tubing, and valves made from copper alloy and exposed to inside air (external
 
environment) experience no AERMs and require no AMPs. Aluminum alloy heat exchanger subcomponents in an air/gas environment experience fouling due to particulate buildup, and are
 
managed by the One-Time Inspection Program.
In a RAI 3.3.2.1.20-1, dated October 12, 2004. the staff asked for additional justification that there are no AERMs, including a loss of heat transfer, for the copper alloy heat exchanger
 
components in this system. In its response, by letter November 3, 2004, the applicant stated that the components in question are the u-bend connectors for the internal cooling coil in the
 
room coolers. These components are likely to be exposed to condensation and, therefore, may
 
experience loss of material; however, they are ex ternal to the cooler such that loss of heat transfer is not a concern. The applicant proposes to use the Systems Monitoring Program to
 
manage the identified aging effect. The staff found that the applicant had identified the
 
appropriate aging effects for the above component and had proposed an acceptable AMP.
 
Therefore, the staff found this acceptable.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the above RAIs, the staff found the aging effects of the
 
above emergency equipment cooling water syst em component types are consistent with industry experience for these combinations of materials and environments. The staff did not
 
identify any omitted aging effects. Therefore, the staff found that the applicant had identified the
 
appropriate aging effects for the materials and environments associated with the above
 
components in the emergency equipment cooling wa ter system. Therefore, RAI 3.3.2.1.20-1 is considered resolved.
3.3.2.3.21  Reactor Water Cleanup System -
Summary of Aging Management Evaluation -
Table 3.3.2.21 The staff reviewed LRA Table 3.3.2.21, which summarizes the results of AMR evaluations for the reactor water cleanup system component groups.
In LRA Table 3.3.2.21, the applicant identifies the aging effects of the reactor water cleanup system components within the scope of license r enewal and subject to AMR. The AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs. The only AMR
 
that does not rely on the GALL Report is as follows: valves made from copper alloy and
 
exposed to inside air (external environment) experience no AERMs and require no AMPs. Heat exchangers made of carbon and low-alloy steel and exposed to treated water (internal)
 
experience loss of material due to crevice, general, and pitting corrosion.
3-246 In general RAI 3.3.2.1-1, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the above RAI, the staff found the aging effects of the
 
above AMR items are consistent with industry ex perience for these combinations of materials and environments. The staff did not identify any omitted aging effects or the need for any AMPs for the above combinations of material and environment. Therefore, the staff found that there is
 
reasonable assurance that the component intended functions will be maintained consistent with
 
the CLB for the period of extended operation, as required by 10 CFR 54.29(a).
LRA Table 3.3.2.21 identifies the Closed-Cycle Water Cooling System Program for managing the aging effects described above.
The staff's detailed review of this AMP is found in SER Section 3.0.3.2.12.
 
Crack Initiation and Growth due to SCC for Stainless Steel and Cast Austenitic Stainless Steel in Treated Water Environments. The staff reviewed LRA Table 3.3.2.21, which summarized the results of AMR evaluations for the reactor water cleanup system component groups. The
 
applicant identified crack initiation and growth due to SCC and change in material properties
 
due to thermal aging as aging effects requiring management for valves constructed of stainless steel and CASS in a treated water environment. The applicant credited the ASME Section XI
 
Inservice Inspection Program to manage these aging effects. During the onsite audit, the staff
 
inquired as to the ASME class of these valves, whether they are currently included in the ASMESection XI Subsections IWB, IWC and IWD Inservice Inspection Program, and the basis for
 
concluding that the ASME inspection will detect changes in material properties.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the CASS valves that are included in this line item are the reactor water cleanup system 1-
 
inch root valves providing flow to and from the recently added durability monitoring panels forUnits 2 and 3. These valves are non-nuclear Code class, therefore, the ASME Section XI
 
Subsections IWB, IWC and IWD Inservice Inspection Program is not applicable.
 
The applicant further stated that thermal embrittlement degrades the mechanical properties of
 
material (strength, ductility, toughness) as a result of prolonged exposure to high temperatures.
 
CASS materials are susceptible to thermal embrittlement. The degree of susceptibility is
 
dependent upon material composition and time at temperature. The maximum time these valves
 
would be exposed to these high temperatures would be for Unit 3. The Unit 3 valves were
 
installed in the spring 2000 refueling outage with a proposed license expiration date of July 2, 2036. This represents a potential for approximately 36.5 years of operation at the elevated
 
temperatures. The Unit 2 valves were installed in the spring 2001 refueling outage with a
 
proposed license expiration date of June 28, 2034, or approximately 33.5 years of operation.
 
None of these CASS valves will be operated beyond their original 40-year design life and
 
thermal aging has not been identified as a current license basis (40 years) issue.
The applicant referenced NRC letter, "License Renewal Issue No. 98-0030, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Components," dated May 19, 2000 from Mr. C.
 
I. Grimes (NRC) to D. J. Walters (NEI), to support its position that change in material properties 3-247 due to thermal aging is not a concern for these valves, citing the results of a bounding fracture mechanics analysis for valve bodies of less than 4-inch NPS, included in Attachment 2 to this
 
letter. The applicant concluded that thermal aging of these 1-inch NPS CASS valves is not an AERM, based on the following considerations:
* Thermal aging is not a CLB issue and is not a concern for operation beyond forty years.
These valves will be operated for less than forty years, including the period of extended
 
operation.
* Even assuming thermal aging for valves is a CLB concern, the conclusion from the NRC's bounding fracture analysis for valves less than NPS 4 was that "a CASS valve
 
loaded to the maximum anticipated stress can sustain a through wall crack well in
 
excess of its wall thickness without fracturing" and "that requirements for licensees to
 
either (a) inspect . . . of these components would represent an unnecessary duplication
 
of effort." However, to resolve this issue, the applicant stated that thermal aging will be identified in the LRA as being an AERM for these 1-inch NPS non-Class 1 valves, and that the Systems
 
Monitoring Program will be identified as the AM P to perform an external visual inspection.
The staff concluded that the applicant's response is acceptable on the basis that: (1) the valves have operating lives less than 40 years; (2) NRC-sponsored fracture mechanics analyses
 
demonstrate a high degree of flaw tolerance, including through-wall cracking; and (3) periodic
 
external visual examination conducted as part of the Systems Monitoring Program will detect through-wall cracking, in the unlikely event that it should occur.
During the onsite audit, the staff also asked why the BWR Stress Corrosion Cracking Program is not credited for this aging effect in all cases. By letter dated October 8, 2004, the applicant
 
submitted its formal response to the staff, stating that Table 3.3.2.21, lines 24 and 54 refer to
 
fittings and piping that are less than 4-inch NPS. The corresponding GALL Report Volume 2, Item IV.C1.1-i, references the ASME Section XI Subsections IWB, IWC, and IWD Inservice
 
Inspection Program, the Chemistry Control Pr ogram, and the One-Time Inspection Program.
For fittings and piping greater than or equal to 4-inch NPS, line items 27 and 56 specify the
 
BRW Stress Corrosion Cracking Program and the Chemistry Control Program, which is
 
consistent with Item IV.C1.1-f. Table 3.3.2.21, line 102 credits the BWR Stress Corrosion
 
Cracking Program and the chemistry control program for aging management of Valves-RCPB, which is consistent with IV.C1.3-c. Note that the BWR Stress Corrosion Cracking Program invokes the ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program for
 
inspection and flaw evaluation to monitor IGSCC.
The applicant further stated that LRA Table 3.3.2.21, rows 20, 49, and 93, for non-reactor coolant pressure boundary fittings, piping, and valves, respectively, incorrectly listed the ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program and/or BWR Stress
 
Corrosion Cracking Program. The correct AMPs for rows 20, 49, and 93 are the Chemistry
 
Control Program and One-Time Inspection Program.
3-248The staff found that the applicant's use of the ASME Code Section XI Program for components less than 4" NPS is consistent with the GALL Report, and also concurred with the applicant's
 
corrections to LRA Table 3.3.2.21. The staff found the applicant's response to be acceptable.
3.3.2.3.22  Reactor Building Closed Cooling Water System - Summary of Aging Management Evaluation - Table 3.3.2.22 The staff reviewed LRA Table 3.3.2.22, which summarizes the results of AMR evaluations for the reactor building closed cooling water system component groups.
In LRA Table 3.3.2.22, the applicant identifies the aging effects of the reactor building closed cooling water system components within the scope of license renewal and subject to AMR. The
 
AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs.
 
The AMR line items that do not rely on the GALL Report include the following: fittings, piping, and valves made from copper alloy and exposed to inside air (external environment) experience no AERMs and require no AMPs. Carbon and low-alloy steel components (fittings, heat
 
exchangers, piping, pumps, tanks, and valves) in treated water are exposed to loss of material
 
due to general, pitting, crevice, and galvanic corrosion, and are managed by the Closed-Cycle Cooling Water System Program.
In general RAI 3.3.2.1-1, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the RAI, the staff found the aging effects of the above
 
reactor building closed cooling water system component types are consistent with industry
 
experience for these combinations of materials and environments. The staff did not identify any
 
omitted aging effects. Therefore, the staff found that the applicant had identified the appropriate
 
aging effects for the materials and environments associated with the above components in the
 
reactor building closed cooling water system.
3.3.2.3.23  Reactor Core Isolation Cooling System - Summary of Aging Management Evaluation - Table 3.3.2.23 The staff reviewed LRA Table 3.3.2.23, which summarizes the results of AMR evaluations for the reactor core isolation cooling system component groups.
In LRA Table 3.3.2.23, the applicant identified the aging effects of the reactor core isolation cooling system components within the scope of license renewal and subject to AMR. The AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs. The
 
AMR line items that do not rely on the GALL Report include the following: heat exchangers, pumps, strainers, and valves made from copper alloy and exposed to inside air (external
 
environment) experience no AERMs and require no AMPs. Aluminum alloy fittings in treated water experience crack initiation and growth due to SCC and loss of material due to crevice, pitting, and galvanic corrosion, and are managed with the Chemistry Control Program and the
 
One-Time Inspection Program. Copper alloy valves in treated water can experience loss of
 
material due to flow-accelerated corrosion, and are managed through the Flow-Accelerated
 
Corrosion Program.
3-249 In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
In RAI 3.3.2.1.23-1, dated October 12, 2004, the staff requested the applicant to explain why loss of heat transfer is not an applicable AERM for the copper alloy heat exchanger components
 
in inside air. In its response dated November 3, 2004, the applicant clarified that these
 
components are the connectors for the lube oil lines going to the internal copper tubes. The staff
 
concluded that heat transfer is not an intended function for these connectors. In addition, these
 
connectors remain above ambient temperature, such that there is no condensation that would
 
lead to other aging effects. The staff concurred that there will be no other aging effects in the
 
absence of condensation or pooling. Based on the above, the staff found the applicant's
 
response acceptable.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the RAI, the staff found the aging effects of the above
 
reactor core isolation cooling system component types are consistent with industry experience for these combinations of materials and environments. The staff did not identify any omitted
 
aging effects. Therefore, the staff found that the applicant had identified the appropriate aging
 
effects for the materials and environments associated with the above components in the reactor
 
core isolation cooling system.
3.3.2.3.24  Auxiliary Decay Heat Removal Sy stem - Summary of Aging Management Evaluation
- Table 3.3.2.24 The staff reviewed LRA Table 3.3.2.24, which summarizes the results of AMR evaluations for the auxiliary decay heat remo val system component groups.
In LRA Section 3.3.2.24 and Table 3.3.2.24, the applicant identified the materials, environments, and AERMs. The materials identified include carbon steel, low-alloy steel, and
 
stainless steel. The applicant identified the environments to which these materials could be
 
exposed as air gas and inside air. The applicant identified loss of material from general and
 
pitting corrosion and of bolting function due to general corrosion.
The staff reviewed the LRA to determine whether the applicant had demonstrated that it would adequately manage the effects of aging for the auxilia ry decay heat removal system during the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff reviewed LRA
 
Section 3.3.2.24 and Table 3.3.2.24 for completeness and consistency with the GALL Report
 
and industry experience.
The staff found that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.25  Radioactive Waste Treatment Syst em - Summary of Aging Management Evaluation
- Table 3.3.2.25 The staff reviewed LRA Table 3.3.2.25, which summarizes the results of AMR evaluations for the radioactive waste treatment system component groups.
3-250 In LRA Table 3.3.2.25, the applicant identifies the aging effects of radioactive waste treatment system components within the scope of license r enewal and subject to AMR. The AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line
 
items that do not rely on the GALL Report include the following: valves made from copper alloy and exposed to inside air (external environment) experience no AERMs and require no AMPs.
Carbon and low-alloy steel components (fittings, piping, and valves) in raw water experience loss of material due to general, crevice, and pitting corrosion, galvanic corrosion, and MIC, and
 
are managed through the One-Time Inspection Program. Carbon and low-alloy steel
 
components (fittings, piping, and valves) in treated water experience loss of material due to
 
general, crevice, pitting, and galvanic corrosion, and are managed by the One-Time Inspection Program. For cast iron and cast iron alloy pumps in treated water, the applicant uses the
 
One-Time Inspection Program to manage loss of material due to general, crevice and pitting
 
corrosion.
For elastomer (neoprene and silicon) fittings in air/gas and inside air, the applicant does not identify any AERMs or AMPs.
Additional items the technical staff was also asked to review include the following AMR line items that do not rely on the GALL Report: aluminum alloy fittings and piping in treated water
 
may experience crack initiation and growth due to SCC and a loss of material due to crevice
 
and pitting corrosion, and are managed by the C hemistry Control Program and the One-Time Inspection Program, while the aluminum alloy in air experiences no AERMs. For the copper
 
alloy (bronze) fittings, the bronze in treated water may experience a loss of material due to
 
crevice and pitting corrosion and loss of material due to selective leaching, which are managed
 
by the One-Time Inspection Program and Selective Leaching of Materials Program, respectively, while the bronze in inside air experiences no AERMs. For the cast iron and cast
 
iron alloy strainers, the side exposed to treated water may experience loss of material due to
 
general, crevice, and pitting corrosion and a loss of material due to selective leaching, which are
 
managed by the One-Time Inspection Program and the Selective Leaching of Materials
 
Program, respectively, while the side in inside air experiences loss of material due to general
 
corrosion and is managed through the Systems Monitoring Program.
In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
In RAI 3.3.2.1.23-1, dated October 12, 2004, the staff asked for additional information related to elastomer components, since the applicant determined that there are no AERMs based on
 
industry guidance. The degradation of elastomers depends on the environmental factors such
 
as the temperature, radiation levels, and presence of aggressive chemicals (aggressive
 
chemicals are not anticipated for this system). In its response dated November 3, 2004, the
 
applicant demonstrated that the temperature and radiation levels remain below the thresholds
 
for which there is significant aging of the silicon and neoprene. Therefore, the staff concurred
 
with the applicant's assessment.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's responses to the RAIs, the staff found the aging effects of the above
 
radioactive waste treatment system component types are consistent with industry experience for 3-251 these combinations of materials and environments. The staff did not identify any omitted aging effects. Therefore, the staff found that the applicant identified the appropriate aging effects for
 
the materials and environments associated with the above components in the radioactive waste
 
treatment system.
3.3.2.3.26  Fuel Pool Cooling and Cleanup System - Summary of Aging Management Evaluation - Table 3.3.2.26 The staff reviewed LRA Table 3.3.2.26, which summarizes the results of AMR evaluations for the fuel pool cooling and cleanup system component groups.
In LRA Table 3.3.2.26, the applicant identifies the aging effects of the spent fuel pool cooling and cleanup system components within the scope of license renewal and subject to AMR. The
 
AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs.
 
The AMR line items that do not rely on the GALL Report include the following: for aluminum
 
alloy components (fittings, piping, and valves) in treated water, the applicant identifies crack
 
initiation and growth due to SCC and loss of material due to crevice and pitting corrosion, and
 
galvanic corrosion, and credits the Chemistry Control Program and the One-Time Inspection
 
Program.On the basis of its review of the information provided in the LRA, the staff found the aging effects of the above spent fuel pool c ooling and cleanup system component types are consistent with industry experience for these combinations of materials and environments. The
 
staff did not identify any omitted aging effects. Therefore, the staff found that the applicant
 
identified the appropriate aging effects for the materials and environments associated with the
 
above components in the spent fuel pool cooling and cleanup system.
3.3.2.3.27  Fuel Handling and Storage System
- Summary of Aging Management Evaluation -
Table 3.3.2.27 The staff reviewed LRA Table 3.3.2.27, which summarizes the results of AMR evaluations for the fuel handling and storage system component groups.
In Section 3.3.2.27 and LRA Table 3.3.2.27, the applicant identified the materials, environments, and AERMs. The materials identified include aluminum alloy, carbon steel, low-alloy steel, and stainless steel. The applicant identified the environments to which these
 
materials could be exposed as inside air and treated water. The applicant identified loss of
 
material from crack initiation and growth due to stress corrosion; loss of material due to crevice, pitting, general, and galvanic corrosion of bolting function due to stress relaxation; and loss of
 
material due to mechanical wear.
The staff reviewed the LRA to determine whether the applicant had demonstrated that it would adequately manage the effects of aging for the serv ice air system during the period of extended operation, as required by 10 CFR 54.21(a)(3). Additionally, the staff considered the aging effect
 
loss of of bolting function due to stress relaxation, which is addressed in SER Section 3.3.2.36.
 
The staff reviewed LRA Section 3.3.2.27 and Table 3.3.2.27 for completeness and consistency
 
with the GALL Report and industry experience.
3-252 3.3.2.3.28  Diesel Generator System -
Summary of Aging Management Evaluation -
Table 3.3.2.28 The staff reviewed LRA Table 3.3.2.28, which summarizes the results of AMR evaluations for the diesel generator system component groups.
In LRA Table 3.3.2.28, the applicant identifies the aging effects of the diesel generator system components within the scope of license renewal and subject to AMR. The AMR lists the
 
materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line
 
items that do not rely on the GALL Report include the following: fittings, piping, tubing, and
 
valves made from copper alloy and exposed to inside air (external environment) experience no AERMs and require no AMPs. For stainless steel fittings in treated water, the applicant identifies
 
crack initiation/growth due to SCC and loss of material due to crevice and pitting corrosion, and
 
credits the Closed-Cycle Cooling Water Program.
For flexible connectors made from elastomer and exposed to treated water (internal) and inside air (external), the applicant identifies
 
elastomer degradation due to thermal exposure and credits the Systems Monitoring Program.
For flexible connectors made from elastomer and exposed to inside air, the applicant identifies
 
elastomer degradation due to thermal exposure and ultraviolet radiation, and credits the
 
Systems Monitoring Program. LRA Table 3.3.2.28 also identifies wear as an AERM for the
 
elastomer flexible connectors, and credits the Systems Monitoring Program.
In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the above RAI, the staff found the aging effects of the
 
above diesel generator system component types ar e consistent with industry experience for these combinations of materials and environments. The staff did not identify any omitted aging
 
effects. Therefore, the staff found that the applicant identified the appropriate aging effects for
 
the materials and environments associated with the above components in the diesel generator system.Crack Initiation and Growth due to SCC for Copper Alloys and Stainless Steel in Raw Water Environments. The applicant identified crack initiation and growth due to SCC as an AERM for heat exchangers constructed of copper alloy in a raw water environment. The applicant credited
 
the Open-Cycle Cooling Water System Program to manage this aging effect. The staff asked how the Open-Cycle Cooling Water System Progr am will detect cracking prior to the loss of intended function for these components. By letter dated October 8, 2004, the applicant
 
submitted its formal response to the staff, st ating that the Open-Cycle Cooling Water System Program is implemented by a variety of maintenance, inspection, and testing procedures. The
 
primary method of detecting cracking in heat exchangers is eddy current testing in accordance
 
with the heat exchanger program (NEDP-17). This procedure requires the heat exchanger engineer to coordinate and schedule heat exchanger activities. The actual inspections are
 
scheduled as preventive maintenance tasks. In particular, the diesel generator cooling water
 
heat exchangers are scheduled with a frequency of two years.
The staff concluded that the applicant's response is acceptable for this material and environment combination since the Open-Cycle C ooling Water System Program is implemented 3-253 by a variety of maintenance, inspection, and testing procedures, which include eddy current testing in accordance with the heat exchanger program. Eddy current testing will detect
 
cracking.
3.3.2.3.29  Control Rod Drive System -
Summary of Aging Management Evaluation -
Table 3.3.2.29 The staff reviewed LRA Table 3.3.2.29, which summarizes the results of AMR evaluations for the CRD system component groups.
In LRA Table 3.3.2.29, the applicant identifies the aging effects of the CRD system components within the scope of license renewal and subject to AMR. The AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line items that do not rely on the GALL Report include the following: fittings, heat exchangers, and valves
 
made from copper alloy and exposed to inside air (external environment) experience no AERMs and require no AMPs. Aluminum alloy fittings in treated water are subjected to crack
 
initiation/growth due to SCC and loss of material due to crevice and pitting corrosion, and are
 
managed by the Chemistry Control Program and the One-Time Inspection Program.
In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the
 
copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the above RAI, the staff found the aging effects of the
 
above CRD system component types are consist ent with industry experience for these combinations of materials and environments. The staff did not identify any omitted aging effects.
 
Therefore, the staff found that the applicant identified the appropriate aging effects for the
 
materials and environments associated with the above components in the CRD system.
Crack Initiation and Growth due to SCC for Stainless Steel and Cast Austenitic Stainless Steel in Treated Water Environments The applicant identified loss of material due to corrosion as an AERM for fittings, piping, strainers, and valves constructed of stainless steel in a treated water
 
environment. However, cracking due to SCC was only identified for valves. The staff inquired as
 
to why cracking due to SCC was not identified for stainless steel fittings, piping, and strainers in
 
a treated water environment for this system. By letter dated October 8, 2004, the applicant
 
submitted its formal response to the staff, stating that stainless steel components have the
 
potential for corrosion if the chemistry control program is not properly implemented. However, stress corrosion cracking only requires an AMP where the normal operating temperature is greater than 140 °F. The AMR identifies that the CRD system RCPB components (valves) that
 
interface with the reactor water cleanup system experience normal operating temperatures in excess of 140 °F. These closed valves are the only components in the CRD system that exceed 140 °F.The staff concluded that the applicant's determination that cracking due to SCC is only applicable to RCPB valves in the CRD system is acceptable since these are the only components that operate at temperatures above 140 °F.
3-254 3.3.2.3.30  Diesel Generator Starting Air Sy stem - Summary of Aging Management Evaluation
- Table 3.3.2.30 The staff reviewed LRA Table 3.3.2.30, which summarizes the results of AMR evaluations for the diesel generator starting air system component groups.
In LRA Table 3.3.2.30, the applicant identifies the aging effects of the diesel generator starting air system components within the scope of lic ense renewal and subject to AMR. The AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR
 
line items that do not rely on the GALL Report include the following: fittings, flexible connectors, piping, tubing, and valves made from copper alloy and exposed to inside air (external
 
environment) experience no AERMs and require no AMPs. Flexible connectors made of elastomer in an air/gas (internal) and inside air (external) environment exhibit no AERMs and
 
require no AMPs. Strainers made of stainless steel in an air/gas (internal) and inside air (external) environment exhibit no AERMs and require no AMPs.
In a general RAI, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the copper
 
alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
Depending on the environmental conditions such as temperature, ultraviolet radiation, and aggressive chemicals, there is the potential for elastomers to experience aging effects and
 
require aging management. The applicant was asked to clarify that there are no aging effects
 
commensurate with the environment exposed to or to provide appropriate aging management for these components (as they have done for num erous other systems); however, the applicant discussed the diesel generator system instead.
By letter dated May 24, 2005 the applicant submitted additional information in regard to the management of elastomers in the diesel generator starting air system. The applicant clarified that the rubber flexible connector can be exposed to a maximum temperature of about 115 °F
 
and, conservatively, thermal stress is considered an applicable aging effect. The applicant
 
identified that the Systems Monitoring Program will be used to manage the external surface and the internal surface will be managed by the One-Time Inspection Program. The applicant also
 
clarified that no specific recommendations were provided by the manufacturer regarding service life and appropriate inspections.
The staff reviewed the applicant's response and found the response to be reasonable and acceptable because the applicant identified that the external and internal surfaces of the rubber
 
flexible connectors will be managed by the Sy stems Monitoring Program and the One-Time Inspection Program, respectively. There is reasonable assurance that these AMPs are capable
 
of detecting and correcting degradation of the elastomers caused by thermal or other
 
environmental aging factors prior to adversely affecting the intended function of the
 
components.
On the basis of its review of the information provided in the LRA and the RAI response, the staff found the applicant's assessment consistent with industry experience for this combination of
 
material and environment. The staff did not identify any omitted aging effects or the need for any
 
AMPs for this combination of material and environment. Therefore, the staff found that there is
 
reasonable assurance that the intended functions of the above components of the diesel 3-255 generator starting air system will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.29(a).
3.3.2.3.31  Radiation Monitoring System
- Summary of Aging Management Evaluation -
Table 3.3.2.31 The staff reviewed LRA Table 3.3.2.31, which summarizes the results of AMR evaluations for the radiation monitoring system component groups.
In LRA Table 3.3.2.31, the applicant identifies the aging effects of the radiation monitoring system components within the scope of license r enewal and subject to AMR. The AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line
 
items that do not rely on the GALL Report include the following: fittings, pumps, strainers, and
 
valves made from copper alloy and exposed to inside air (external environment) experience no AERMs and require no AMPs. Traps made from aluminum alloy exposed to raw water are subjected to crack initiation/growth due to SCC, and will be managed by the One-Time
 
Inspection Program. Tubing made from polymer (tygon) in air/gas experience no AERMs and require no AMPs.
In a general RAI, the staff questioned whether the copper alloy components exposed to inside air would be subject to aging effects. The staff found the applicant's assessment of the copper
 
alloy components to be acceptable, as discussed in SER Section 3.3.2.3.
With respect to the polymer components, in response to the staff's informal request of February 11, 2005, by letter dated March 11, 2005, the applicant clarified that the polymer
 
components are tygon tubing in air/gas and inside air. The applicant stated that once the proper
 
polymer, resistant to the environment, is chosen, there are no AERMs. The applicant further
 
stated that industry guidance does not identify any AERMs for this polymer and environment, but the components would be included in the Systems Monitoring Program to verify that there is no hardening or loss of material strength due to polymer degradation.
On the basis of its review of the information provided in the LRA and the additional information included in the applicant's response to the above RAIs, the staff found the aging effects of the
 
above radiation monitoring system component types are consistent with industry experience for these combinations of materials and environments. The staff did not identify any omitted aging
 
effects. Therefore, the staff found that the applicant had identified the appropriate aging effects
 
for the materials and environments associated with the above components in the radiation
 
monitoring system 3.3.2.3.32  Neutron Monitoring System -
Summary of Aging Management Evaluation -
Table 3.3.2.32 The staff reviewed LRA Table 3.3.2.32, which summarizes the results of AMR evaluations for the neutron monitoring system component groups.
In LRA Section 3.3.2.32 and Table 3.3.2.32, the applicant identified the materials, environments, and AERMs. The materials identified include carbon steel, and low-alloy steel.
 
The applicant identified the environments to which these materials could be exposed as air gas
 
and inside air. The applicant identified loss of material from crack initiation and growth due to 3-256 stress corrosion and cyclic loading, loss of bolting function due to general corrosion and wear and loss of material due to crevice and pitting corrosion
.The staff reviewed the LRA to determine whether the applicant had demonstrated that it would
 
adequately manage the effects of aging for the neutron monitoring system during the period of
 
extended operation, as required by 10 CFR 54.21(a)(3). The staff reviewed LRA
 
Section 3.3.2.32 and Table 3.3.2.32 for completeness and consistency with the GALL Report
 
and industry experience.
The staff found that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.33  Traversing In-Core Probe System
- Summary of Aging Management Evaluation -
Table 3.3.2.33 The staff reviewed LRA Table 3.3.2.33, which summarizes the results of AMR evaluations for the traversing in-core probe system component groups.
In LRA Section 3.3.2.33 and Table 3.3.2.33, the applicant identified the materials, environments, and AERMs. The materials identified include stainless steel. The applicant
 
identified the environments to which these materials could be exposed as air gas and inside air.
 
The applicant has not identified any loss of material nor any aging effects.
The staff reviewed LRA Section 3.3.2.33 and Table 3.3.2.33 for completeness and consistency with the GALL Report and industry experience.
The staff found that the applicant demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.34  Cranes System - Summary of Aging Management Evaluation - Table 3.3.2.34
 
The staff reviewed LRA Table 3.3.2.34, which summarizes the results of AMR evaluations for the cranes system component groups.
In Section 3.3.2.34 and LRA Table 3.3.2.34, the applicant identified the materials, environments, and AERMs. The materials identified include carbon steel, and low-alloy steel.
 
The applicant identified the environments to which these materials could be exposed as inside
 
air. The applicant identified loss of material from crack initiation, loss of bolting function due to
 
stress relaxation and wear, loss of material due to general corrosion and mechanical wear.
The staff reviewed the LRA to determine whether the applicant had demonstrated that it would adequately manage the effects of aging for the cranes system during the period of extended
 
operation, as required by 10 CFR 54.21(a)(3). Additionally, the staff considered the aging effect, loss of of bolting function due to stress relaxation, which is addressed in SER Section 3.3.2.36.
 
The staff reviewed LRA Section 3.3.2.34 and Table 3.3.2.34 for completeness and consistency
 
with the GALL Report and industry experience.
3-257 The staff found that the applicant demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
Conclusion. On the basis of its review, the staff found that the applicant had appropriately evaluated AMR results involving material, environment, aging effects requiring management, and AMP combinations that are not evaluated in the GALL Report for entries shown in
 
Table 3.3-1. The staff found that the applicant had demonstrated that the effects of aging will be
 
adequately managed so that the intended functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff also reviewed LRA Table 3.3.2.9, which summarized the results of AMR evaluations for the heating, ventilation, and air conditioning system component groups.
The applicant identified no aging effect or AMP for heat exchangers constructed of aluminum alloy and copper alloy in an outside air environment on the external surface. The staff inquired
 
as to the technical justification for concluding that there are no aging effects for this
 
material/environment combination for this system. By letter dated October 8, 2004, the applicant
 
submitted its formal response to the staff, stating that the cooling coils identified in an outside
 
environment are in the Freon cycle and the air fl ow over the coils is to cool the Freon.
Therefore, condensation on the coils; will not occur and loss of material is not identified as an
 
aging mechanism requiring management for the period of extended operation. Air side fouling of
 
cooling coils that have no condensation mechanism is only a problem for fin type heat
 
exchangers. Therefore, fouling is not identified as an aging mechanism requiring management
 
for the period of extended operation.
The staff concluded that the applicant's response is acceptable since these components are cooling coils exposed to air flow on the outside surface. The air flow is to cool Freon inside the
 
coils; therefore, the air will be heated and condensation will not occur on these components.
 
The applicant also identified no aging effect or AMP for heat exchangers constructed of copper
 
alloy in an air/gas environment on their internal surface. The staff inquired as to the technical
 
justification for concluding that there are no aging effects for these material and environment
 
combinations for components in this system. By letter dated October 8, 2004, the applicant
 
submitted its formal response to the staff, stating that Table 3.3.2.9, rows 131 and 132 are
 
referring to the Freon side of the cooling coil and correctly identify no aging effects. The material
 
should reference Freon in the materials description. These items are for the external surface of
 
cooling coils and correctly identify loss of material.
The staff concluded that the applicant's response is acceptable since the components will be exposed to Freon, which is not a corrosive environment for copper alloys. The staff also
 
concurred with the corrections to Table 3.3.2.9, rows 131 and 132.
The staff reviewed LRA Table 3.3.2.2, which summarized the results of AMR evaluations for the fuel oil system component groups. The applicant identified no aging effect or AMP for
 
components constructed of cast iron and cast iron alloy, as well as carbon or low-alloy steel in
 
an air/gas environment on their internal surface. The staff inquired as to the technical
 
justification for concluding that there are no aging effects for these material/environment
 
combinations for components in this system. By letter dated October 8, 2004, the applicant
 
submitted its formal response to the staff, stat ing that components in the fuel oil system are 3-258 exposed to a fuel oil vapor environment. This f uel oil vapor environment protects the component surfaces and prevents internal corrosion.
The staff concluded that the applicant's determination of no AERM for components in the fuel oil system in an air/gas environment on the inter nal surface is acceptable since the components will be exposed to fuel oil vapor, which will protect the surfaces of the components from corrosion.
The staff reviewed LRA Table 3.3.2.3, which summarized the results of AMR evaluations for the residual heat removal service water system component groups.
The applicant identified no aging effect or AMP for components constructed of cast iron and cast iron alloy, as well as carbon or low-alloy steel in an embedded/encased environment on
 
their external surface. The staff inquired as to the technical justification for concluding that there
 
are no aging effects for these material and environment combinations for components in this
 
system. By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that no aging effects are identified for embedded/encased components. If excessive
 
corrosion that could prevent the performance of the intended functions during the period of
 
extended operation was detected on the inside surface or outside surface in air environments
 
adjacent to the embedded/encased portions, corrective actions would be taken to restore the
 
component, including the embedded/encased portions, if this was determined to be necessary.
The staff concluded that the applicant's determination of no AERM for components in the residual heat removal service water sy stem in an embedded/encased environment is acceptable since exposure to a corrosive env ironment will be limited. Inspections will be performed on adjacent surfaces exposed to an air environment. If corrosion is detected on
 
adjacent surfaces in an air environment, corrective actions will be taken to restore the
 
component, including the embedded/encased portions, if this is determined to be necessary.
The staff reviewed LRA Table 3.3.2.16, which summarized the results of AMR evaluations for the raw water chemical treatment system component groups.
The applicant identified no aging effect or AMP for fittings, piping, and valves constructed of polymer with a raw water environment on the internal surface. The staff inquired as to the
 
technical justification for concluding that there are no aging effects for this material/environment
 
combination for this system. By letter dated October 8, 2004, the applicant submitted its formal
 
response to the staff, stating that the polymer referred to in Table 3.3.2.16 is the internal surface
 
of polypropylene-lined carbon steel components. The LRA does not credit the lining for
 
prevention of corrosion and this material/environment combination should be deleted.
The staff found that the applicant's response is acceptable, because the LRA does not credit the lining for prevention of corrosion on the internal surface. The staff also concurred with the
 
correction to Table 3.3.2.16, to delete this material/environment combination.
 
====3.3.3 Conclusion====
The staff concluded that the applicant had provided sufficient information to demonstrate that the effects of aging on the auxiliary systems co mponents that are within the scope of license renewal and subject to an AMR will be adequately managed so that the intended function(s) will 3-259 be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff also reviewed the applicable UFSAR supplement program summaries and concluded that they adequately describe the AMPs credit ed for managing aging of the auxiliary systems, as required by 10 CFR 54.21(d).
3-2603.4  Aging Management of Steam and Power Conversion System This section of the SER documents the staff's review of the applicant's AMR results for the steam and power conversion sy stem components and component groups associated with thefollowing systems:
* main steam
* condensate and demineralized water
* feedwater
* heater drains and vents
* turbine drains and miscellaneous piping
* condenser circulating water
* gland seal water3.4.1  Summary of Technical Information in the Application In LRA Section 3.4, the applicant provided AMR results for components. In LRA Table 3.4.1,"Summary of Aging Management Evaluations for Steam and Power Conversion System Evaluated in Chapter VIII of NUREG-1801," the applicant provided a summary comparison of its
 
AMRs with the AMRs evaluated in the GALL R eport for the steam and power conversion system components and component groups.
The applicant's AMRs incorporated applicable operating experience in the determination of AERMs. These reviews included evaluation of plant-specific and industry operating experience.
 
The plant-specific evaluation included reviews of condition reports and discussions with
 
appropriate site personnel to identify AERMs. The applicant's review of industry operating
 
experience included a review of the GALL Report and operating experience issues identified
 
since the issuance of the GALL Report.
 
====3.4.2 Staff====
Evaluation The staff reviewed LRA Section 3.4 to determine if the applicant had provided sufficient information to demonstrate that the effects of aging for the steam and power conversion system components that are within the scope of license renewal and subject to an AMR will be
 
adequately managed so that the intended functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff performed an onsite audit, during the weeks of June 21 and July 26, 2004, of AMRs to confirm the applicant's claim that certain identified AMRs were consistent with the GALL Report.
 
The staff did not repeat its review of the matters described in the GALL Report; however, the
 
staff did verify that the material presented in the LRA was applicable and that the applicant had
 
identified the appropriate GALL AMRs. The staff's evaluations of the AMPs are documented in
 
SER Section 3.0.3. Detail of the staff's audit evaluation are documented in the BFN audit and
 
review report and are summarized in SER Section 3.4.2.1.
In the onsite audit, the staff also selected AMRs that are consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further
 
evaluations were consistent with the acceptance criteria in SRP-LR Section 3.4.2.2. The staff's 3-261 audit evaluations are documented in the audit and review report and are summarized in SER Section 3.4.2.2.
In the onsite audit, the staff conducted a technical review of the remaining AMRs that are not consistent with, or not addressed in, the GALL Report. The audit and technical review included
 
evaluating whether all plausible aging effects had been identified and evaluating whether the
 
aging effects listed were appropriate for the combinations of materials and environments
 
specified. The staff's audit evaluations are documented in the BFN audit and review report and
 
are summarized in SER Section 3.4.2.3. The staff's evaluation of its technical review is also
 
documented in SER Section 3.4.2.3.
Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or
 
monitoring aging for the steam and pow er conversion system components.
Table 3.4-1, below, provides a summary of the staff's evaluation of components, aging effects/mechanisms, and AMPs listed in LRA Section 3.4, that are addressed in the GALL
 
Report.Table 3.4-1  Staff Evaluation for Steam and Power Conversion System Components in the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation Piping and fittings inmain feedwater line, steam line and in auxiliary feedwater (AFW) piping (PWR only)
(Item Number
 
3.4.1.1)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAAThis TLAA is evaluated in
 
Section 4.3, Metal Fatigue Piping and fittings, valve bodies and
 
bonnets, pump
 
casings, tanks, tubes, tubesheets, channel head and
 
shell (except main steam system)
(Item Number
 
3.4.1.2)Loss of material due to general (carbon steel only), pitting, and crevice
 
corrosionChemistry ControlProgram; One-Time
 
Inspection ProgramChemistry ControlProgram; One-Time
 
Inspection ProgramConsistent withGALL which
 
recommends further
 
evaluation (See
 
Section 3.4.2.2.2)
External surface of carbon steel
 
components (Item Number
 
3.4.1.5)Loss of material due to general corrosionPlant-specificSystems Monitoring Program See Section 3.4.2.2.4 Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-262 Carbon steel piping and valve bodies (Item Number
 
3.4.1.6)Wall thinning due toflow-accelerated
 
corrosionFlow-Accelerated Corrosion ProgramFlow-Accelerated Corrosion ProgramConsistent withGALL which
 
recommends no
 
further evaluation (See Section
 
3.4.2.1)Carbon steel piping and valve bodies to main steam system (Item Number
 
3.4.1.7)Loss of material due to pitting and
 
crevice corrosionChemistry Control ProgramChemistry Control ProgramConsistent withGALL, with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.4.2.1)Closure bolting in high-pressure or
 
high-temperature systems (Item Number
 
3.4.1.8)Loss of material due to general
 
corrosion; crack initiation and growth due to cyclic loading
 
and/or SCC Bolting Integrity Program Bolting Integrity ProgramConsistent withGALL with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.4.2.1)Heat exchangers and coolers/condensers
 
serviced by open-cycle cooling water (Item Number
 
3.4.1.9)Loss of material due to general (carbon steel only), pitting, and crevice
 
corrosion, MIC, and
 
biofouling; buildup
 
of deposit due to
 
biofoulingOpen-Cycle CoolingWater System
 
ProgramOpen-Cycle CoolingWater System
 
ProgramConsistent withGALL which
 
recommends no
 
further evaluation (See Section
 
3.4.2.1)Heat exchangers and coolers/condensers
 
serviced by closed-cycle cooling water (Item Number
 
3.4.1.10)Loss of material due to general (carbon steel only), pitting, and crevice
 
corrosionClosed-CycleCooling Water System ProgramClosed-CycleCooling Water System ProgramConsistent withGALL which
 
recommends no
 
further evaluation (See Section
 
3.4.2.1)External surface of aboveground
 
condensate storage
 
tank (Item Number
 
3.4.1.11)Loss of material due to general (carbon steel only), pitting, and crevice
 
corrosion AbovegroundCarbon Steel Tanks
 
Program AbovegroundCarbon Steel Tanks
 
ProgramConsistent withGALL which
 
recommends no
 
further evaluation (See Section
 
3.4.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-263 External surface of buried condensate
 
storage tank and AFW piping (Item Number
 
3.4.1.12)Loss of material due to general, pitting, and crevice
 
corrosion; MIC Buried piping and tanks surveillance Buried piping and tanks inspectionN/ANot applicable At BFN, the
 
condensate storage
 
tanks and piping
 
and fittings associated with the
 
condensate storage
 
tank are not located
 
underground The staff's review of the BFN component groups followed one of several approaches. One approach, documented in SER Section 3.4.2.1, involves the staff's review of the AMR results for
 
components in the steam and power conversion system that the applicant indicated are consistent with the GALL Report and do not require further evaluation. Another approach, documented in SER Section 3.4.2.2, involves the staff's review of the AMR results for
 
components in the steam and power conversion systems that the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third
 
approach, documented in SER Section 3.4.2.3, involves the staff's review of the AMR results for
 
components in the steam and power conversion sy stem that the applicant indicated are not consistent with, or not addressed in, the GALL Report. The staff's review of AMPs that are
 
credited to manage or monitor aging effects of the steam and power conversion system components is documented in SER Section 3.0.3.3.4.2.1  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Not Recommended Summary of Technical Information in the Application. In LRA Section 3.4.2.1, the applicant identified the materials, environments, and AERMs. The applicant identified the following
 
programs that manage the aging effects relat ed to the steam and power conversion system components:
* ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program
* Bolting Integrity Program
* BWR stress corrosion cracking program
* Chemistry Control Program
* Compressed Air Monitoring Program
* Flow-Accelerated Corrosion Program
* One-Time Inspection Program
* Systems Monitoring Program
* Aboveground Carbon Steel Tanks Program
* Selective Leaching of Materials Program
* Buried Piping and Tanks Inspection Program 3-264 Staff Evaluation. In LRA Tables 3.4.2-1 through 3.4.2-7, the applicant provided a summary of AMRs for the steam and power conversion syst em components, and identified which AMRs it considered to be consistent with the GALL Report.
For component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report does not recommend further
 
evaluation, the staff performed an audit and review to determine whether the plant-specific
 
components contained in these GALL Report component groups were bounded by the GALL
 
Report evaluation.
The applicant provided a note for each AMR line item. The notes described how the information in the tables aligns with the information in the GALL Report. The staff audited those AMRs with
 
Notes A through E, which indicated that the AMR was consistent with the GALL Report.
Note A indicated that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the AMP
 
identified in the GALL Report. The staff audited these line items to verify consistency with the
 
GALL Report and the validity of the AMR for the site-specific conditions.
Note B indicated that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP
 
identified in the GALL Report. The staff audited these line items to verify consistency with the
 
GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been
 
reviewed and accepted by the staff. The staff also determined whether the AMP identified by the
 
applicant was consistent with the AMP identified in the GALL Report and whether the AMR was
 
valid for the site-specific conditions.
Note C indicated that the component for the AMR line item is different from but consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent
 
with the AMP identified by the GALL Report. This note indicates that the applicant was unable to
 
find a listing of some system components in the GALL Report. However, the applicant identified
 
a different component in the GALL Report that had the same material, environment, aging
 
effect, and AMP as the component that was under review. The staff audited these line items to
 
verify consistency with the GALL Report. The staff also determined whether the AMR line item
 
of the different component was applicable to the component under review and whether the AMR
 
was valid for the site-specific conditions.
Note D indicated that the component for the AMR line item is different from but consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some
 
exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify
 
consistency with the GALL Report. The staff verified whether the AMR line item of the different
 
component was applicable to the component under review. The staff verified whether the
 
identified exceptions to the GALL AMPs had been reviewed and accepted by the staff. The staff
 
also determined whether the AMP identified by the applicant was consistent with the AMP
 
identified in the GALL Report and whether the AMR was valid for the site-specific conditions.
3-265 Note E indicated that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited. The staff audited these line items
 
to verify consistency with the GALL Report. The staff also determined whether the identified
 
AMP would manage the aging effect consistent with the AMP identified by the GALL Report and
 
whether the AMR was valid for the site-specific conditions.
The staff conducted an audit and review of the information provided in the LRA, as documented in the BFN audit and review report. The staff did not repeat its review of the matters described in
 
the GALL Report. However, the staff did verify that the material presented in the LRA was
 
applicable and that the applicant had identified the appropriate GALL Report AMRs. The staff's
 
evaluation is discussed below.
For aging management evaluations that the applicant stated are consistent with the GALL Report and for which further evaluation is not recommended, the staff conducted its audit to
 
determine whether the applicant's reference to the GALL Report in the LRA is acceptable.
The staff reviewed the LRA to confirm that the applicant had (1) provided a brief description of the system, components, materials, and environment; (2) stated that the applicable aging
 
effects are reviewed and are evaluated in the GALL Report; and (3) identified those aging
 
effects for the steam and power conversion sy stem components that are subject to an AMR.
On the basis of its audit, the staff determined that for AMRs not requiring further evaluation, as identified in LRA Table 3.4.1 (Table 1), the applicant's references to the GALL Report are
 
acceptable, and no further staff review is required.
Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating
 
experience and proposals for managing associated aging effects. On the basis of its review, the
 
staff concluded that the AMR results, which the applicant claimed to be consistent with the
 
GALL Report, are consistent with the AMRs in the GALL Report. Therefore, the staff concluded
 
that the applicant had demonstrated that the effects of aging for these components will be
 
adequately managed so that their intended function(s) will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR54.21(a)(3).3.4.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended Summary of Technical Information in the Application. In LRA Section 3.4.2.2, the applicant provided further evaluation of aging management as recommended by the GALL Report for the steam and power conversion system. For some li ne items consistent with the GALL Report in LRA Tables 3.4.2-1 through 3.4.2-7 (LRA Table 2 in each section), the applicant provided
 
information concerning how it will manage the following aging effects:
* cumulative fatigue damage
* loss of material due to general, pitting, and crevice corrosion
* loss of material due to general, pitting, and crevice corrosion, MIC, and biofouling
* general corrosion 3-266
* loss of material due to general, pitting, crevice corrosion, and MIC
* quality assurance for aging management of NSR components Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report recommends further
 
evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it had
 
adequately addressed the issues that the applicant further evaluated. In addition, the staff
 
reviewed the applicant's further evaluations against the criteria contained in SRP-LR
 
Section 3.4.2.2. Details of the staff's audit are documented in the staff's audit and review report.
 
The staff's evaluation of the aging effects is discussed in the following sections.
3.4.2.2.1  Cumulative Fatigue Damage
 
In LRA Section 3.3.2.2.3, the applicant stated that fatigue is a TLAA, as defined in 10 CFR 54.3.
Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3
 
documents the staff's review of the applicant's evaluation of this TLAA.
3.4.2.2.2  Loss of Material due to General, Pitting, and Crevice Corrosion
 
The staff reviewed the LRA Section 3.4.2.2.2 against the criteria in SRP-LR Section 3.4.2.2.2.
 
SRP-LR Section 3.4.2.2.2 states that loss of material due to general, pitting, and crevice corrosion should be evaluated further for carbon steel piping and fittings, valve bodies and
 
bonnets, pump casings, pump suction and discharge lines, tanks, tubesheets, channel heads, and shells except for main steam system components; and that loss of material due to pitting
 
and crevice corrosion should be evaluated further for stainless steel tanks and heat
 
exchanger/cooler tubes. The Chemistry Control Program relies on monitoring and control of water chemistry based on the guidelines in BWRVIP-79 (EPRI TR-103515) for water chemistry
 
in BWRs; however, corrosion may occur at locations of stagnant flow conditions. Therefore, the
 
effectiveness of the Chemistry Control Program should be verified to ensure that corrosion is
 
not occurring. The GALL Report recommends furt her evaluation of programs to manage loss of material due to general, pitting, and crevice corrosion to verify the effectiveness of the
 
Chemistry Control Program. A one-time inspection of selected components and susceptible
 
locations is an acceptable method to ensure that corrosion is not occurring and that the
 
components' intended function will be maintained during the period of extended operation. The AMP recommended by the GALL Report is XI.M32, "One-Time Inspection."
In LRA Section 3.4.2.2.2, the applicant credits the Chemistry Control Program to manage loss of material for the components requiring further evaluation. The applicant addressed the GALL
 
Report recommendation for further evaluation to veri fy the effectiveness of the chemistry control through the One-Time Inspection Program. The staff reviewed the Chemical Instruction (CI)
 
13.1, Chemistry Program, Revision 20, which im plements chemistry control of primary water used in the steam and power conversion sy stem. The implementing procedure recommends that the effectiveness of the Chemistry Contro l Program should be verified by means of tools like plant action levels at cut-off points established for contaminant concentrations
 
recommended by Industry guidance to ensure that corrosion is not occurring, with corrective
 
actions if these are exceeded. The staff did not find any instances of exceeding action level II or
 
III in the past five years of operation (i.e., levels exceeding O 2 > 100 ppb or chlorides > 150 ppb 3-267 or sulfates > 150 ppb). The staff concluded that the applicant had satisfactorily complied with GALL recommendations in managing this aging effect and demonstrated that the effects of
 
aging for loss of material will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB during the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
3.4.2.2.3  Loss of Material due to General, Pitting, and Crevice Corrosion, Microbiologically Influenced Corrosion, and Biofouling Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3.4.2.2.4  General Corrosion
 
The staff reviewed the LRA Section 3.4.2.2.4 against the criteria in SRP-LR Section 3.4.2.2.4.
 
SRP-LR Section 3.4.2.2.4 states that loss of material due to general corrosion could occur on the external surfaces of all carbon steel SCs, including closure bolting exposed to operating temperature less than 212 °F. The GALL Report recommends further plant-specific evaluation to
 
ensure that this aging effect is adequately managed.
In LRA Section 3.4.2.2.4, the applicant stated that it will implement the Systems Monitoring Program to manage general corrosion of external surfaces exposed to operating temperaturesless than 212 °F.
The applicant credits the Systems Monitoring Pr ogram to manage general corrosion of externalsurfaces exposed to operating temperatures less than 212 °F. This is consistent with the GALL
 
Report. The staff accepted the Systems Monitori ng Program, and its evaluation of this program is documented in SER Section 3.0.3.3.1.
The staff found that the applicant demonstrated that the effects of aging for loss of material will be adequately managed so that the intended functions will be maintained consistent with the
 
CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.4.2.2.5  Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced Corrosion Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not applicable to BFN.
3.4.2.2.6  Quality Assurance for Aging Management of Non-Safety-Related Components SER Section 3.0.4 provides the staff's evaluation of the applicant's quality assurance program.
 
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report
 
recommends further evaluation, the staff determines that (1) those attributes or features for
 
which the applicant claimed consistency with the GALL Report were indeed consistent, and (2)
 
the applicant had adequately addressed the issues that were further evaluated. The staff found 3-268 that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).3.4.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.4.2.1 through 3.4.2.7, the staff reviewed additional details of the results of the AMRs for MEAP combinations that are not
 
consistent with the GALL Report, or that are not addressed in the GALL Report. The
 
components impacted by the AMRs are from the following steam and power conversionsystems:
* Table 3.4.2.1: Main Steam System (001)
* Table 3.4.2.2: Condensate and Demineralized Water System (002)
* Table 3.4.2.3: Feedwater System (003)
* Table 3.4.2.4: Heater Drains and Vents System (006)
* Table 3.4.2.5: Turbine Drains and Miscellaneous Piping System (008)
* Table 3.4.2.6: Condenser Circulating Water System (027)
* Table 3.4.2.7: Gland Seal Water System (037)
In LRA Tables 3.4.2.1 through 3.4.2.7, the applicant indicated, via Notes F through J, that combinations of component type, material, environment, and AERM do not correspond to a line
 
item in the GALL Report, and provided informat ion concerning how the aging effect will be managed. Specifically, Note F indicated that the material for the AMR line item component is not
 
evaluated in the GALL Report. Note G indicated that the environment for the AMR line item
 
component and material is not evaluated in the GALL Report. Note H indicated that the aging
 
effect for the AMR line item component, materi al, and environment combination is not evaluated in the GALL Report. Note I indicated that the aging effect identified in the GALL Report for the
 
line item component, material, and environment combination is not applicable. Note J indicated
 
that neither the component nor the material and environment combination for the line item is
 
evaluated in the GALL Report.
Staff Evaluation. For component type, material, and environment combinations that are not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine
 
whether the applicant had demonstrated that the effects of aging will be adequately managed
 
so that the intended function(s) will be maintained consistent with the CLB during the period of
 
extended operation. The staff's evaluation is discussed in the following sections.
In RAI 3.4-1, dated November 18, 2004, the staff stated that in LRA Tables 3.4.2.1 through 3.4.2.7, carbon and low-alloy steel bolting in an inside air (external) or outside air (external)
 
environment is not identified with the aging effect of cracking requiring management. In
 
RAI 3.4-1, dated November 18, 2004, the staff requested the applicant to discuss the specific
 
material grading used for the bolting in each of the associated systems, and justify the basis for
 
concluding that crack initiation/growth due to SCC is not a concern for the bolting during the
 
period of extended operation. In its response, by letter dated December 16, 2004, the applicant
 
stated that the cracking aging effect is not identified because high-yield bolting materials (yield
 
strength above 150 ksi) had not been identified and a review of the BFN operating experience
 
had not identified any instances where mechanical component failure was attributable to SCC of
 
high-strength bolting. In addition, the use of molybdenum disulfide thread lubricant, which is 3-269 considered to promote SCC, is not allowed by site and engineering procedures. Therefore, loss of bolting function due to SCC of bolted joints of vendor-supplied mechanical equipment is not
 
expected and no aging management is required for the period of extended operation.
Based on the above information provided by the applicant, the staff's concern described in RAI 3.4-1 is resolved.
In RAI 3.4-2, dated November 18, 2004, the staff stated that in LRA Tables 3.4.2.2, 3.4.2.3, 3.4.2.6, and 3.4.2.7, copper-alloy components in an inside air (external) environment are not
 
identified with any aging effects requiring management. Therefore, the staff requested the
 
applicant to provide a discussion of the air environment involved, and to justify the basis for
 
concluding that there are no aging effects requiring management under the
 
material/environment combinations. The staff also requested the applicant to provide a
 
summary description of the stated industry guidance. In its response, by letter dated
 
December 16, 2004, the applicant stated that the copper-alloy components exposed to an
 
inside air (external) environment were evaluated individually to determine where condensation
 
or periodic wetting could occur. Copper-alloy components containing fluid at a temperature
 
below the dew point of the external environment is subject to condensation. The identified aging
 
effects/mechanisms were then determined based on the particular copper alloy present and
 
whether condensation or periodic wetting could occur. Based on this evaluation, the applicant
 
concluded that there were no instances where copper-alloy components with greater than 15
 
percent zinc were subject to an aggressive environment or condensation/periodic wetting.
 
Therefore, no aging effects that require management during the period of extended operation
 
were identified for the copper-alloy components in the subject tables. The applicant also
 
provided a summary description of the industry guidance (i.e., EPRI Technical Report 1003056, "Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools"), which supports the
 
above finding for copper alloy.
Based on the above information provided by the applicant, the staff's concern described in RAI 3.4-2 is resolved.
In RAI 3.4-3, dated November 18, 2004, the staff stated that in LRA Tables 3.4.2.1, 3.4.2.3, 3.4.2.4, and 3.4.2.5, carbon and low-alloy steel bolting in an inside air (external) environment is
 
not identified with any aging effects requiring management. Also, the applicant indicated that
 
carbon and low-alloy steels are not susceptible to external general corrosion when the temperature is greater than 212 °F. Therefore, the staff requested the applicant to discuss the
 
specific temperature environment for bolting, instead of piping, and to justify the basis for
 
concluding that no aging effects need to be identified for the bolting.
In its response, by letter dated December 16, 2004, the applicant stated that LRA Table 3.4.2.1 for the main steam system, LRA Table 3.4.2.3 fo r the feedwater system, LRA Table 3.4.2.4 for the heater drain and vents system, and LRA Table 3.4.2.5 for the turbine drains and
 
miscellaneous piping system do not identify general corrosion as an aging effect for carbon and
 
low-alloy steel bolting in an inside air (external) environment as this bolting is maintained dry by
 
the heat to which it is exposed. The applicant stated that during normal operations the internal
 
environment for those portions of the above sy stems within the scope of license renewal ismuch higher than 212 °F (>300 °F). Since the bolting connections are constantly in contact with
 
the high temperature components within these syst ems, the bolting itself within these systems 3-270will experience temperatures higher than 212 °F. Carbon and low-alloy steels are notsusceptible to external general corrosion at temperatures above 212 °F.
Based on the above information provided by the applicant, the staff's concern described in RAI 3.4-3 is resolved.
In RAI 3.4-4, dated November 18, 2004, the staff stated that in LRA Table 3.4.2.3, carbon and low-alloy steel components in air/gas (internal) - moist air environments are identified as being
 
susceptible to loss of material due to crevice, galvanic, general, and pitting corrosion. In lieu of a
 
periodic inspection program, the One-Time Inspection Program is credited as the only
 
applicable AMP. In LRA Table 3.4.2.6, carbon and low-alloy steel and cast iron and cast
 
iron-alloy components in raw water (internal) environments are identified as being susceptible to
 
loss of material due to biofouling, MIC, crevice, general, and pitting corrosion. The One-Time
 
Inspection Program is credited as the only applicable AMP. Therefore, the staff requested the
 
applicant to provide justification that the One-Time Inspection program, instead of the Periodic
 
Inspection Program, should be used to manage the aging effects for the above components and
 
material/environment combinations.
In its response, by letter dated December 16, 2004, the applicant stated that the carbon and low-alloy steel components in LRA Table 3.4.2.3 for the feedwater system are exposed to an
 
air/gas--moist air environment in two applicati ons. The first application is the small segment between the dual isolation valves on system vents and drains, and the second application is valve packing leakoff lines on Unit 1 feedwater isolation valves. These leakoff lines will be
 
removed prior to Unit 1 restart, and will not be applicable to the LRA.
The small segment of piping/fittings between t he dual isolation valves on system vents and drains is exposed to feedwater quality water when the valves are open to support maintenance
 
activities and has trapped air with varying amount of feedwater, based on how the valves are
 
closed (i.e., the sequence and time between valve closings). The applicant stated that the
 
safety consequences for this short segment of piping failing are minimal as this line is
 
downstream of a closed isolation valve that is manually opened only to support maintenance
 
activities. Minimal degradation is expected based on the quality of the water potentially in these
 
components. For completeness, however, and using the One-Time Inspection Program the
 
applicant will perform inspections to verify that these lines are not degrading. Based on the
 
expected minimal degradation as stated in the above, the staff considered the applicant's
 
proposed use of the One-Time Inspection Program to be acceptable.
In LRA Table 3.4.2.6, for the condenser circulating water system, carbon and low-alloy steel and cast iron and cast iron-alloy components in raw water (internal) environments are identified as
 
being susceptible to loss of material due to biofouling, MIC, crevice, general, and pitting
 
corrosion. The in-scope components in the condenser circulating water system are those
 
components that provide the anti-siphon vacuum breaker function. The applicant stated that
 
upon re-reviewing the license renewal scope for the condenser circulating water system, it was
 
determined that raw water was inadvertently specified as the internal environment for the
 
anti-siphon vacuum breaker components. The app licable internal environment (air/gas) has already been evaluated for this system and is included in the LRA. The raw water environment will be deleted from this system.
3-271 Based on the above information provided by the applicant, the staff's concern described in RAI 3.4-4 is resolved.
In RAI 3.4-5, dated November 18, 2004, the staff stated that in LRA Tables 3.4.2.1 and 3.4.2.3, bolting made of carbon and low-alloy steel, nickel alloy, and stainless steel in inside air (external) environments are identified as being susceptible to loss of bolting function due to
 
wear. The Bolting Integrity Program is credited as the AMP. The staff noted that LRA
 
Section B.2.1.16 does not specifically address "loss of bolting function" due to wear as an aging
 
effect to be managed by the AMP. Therefore, the staff requested the applicant to discuss how
 
the identified aging effect will be managed by the program.
In its response, by letter dated December 16, 2004, the applicant stated that bolting degradation due to wear (fretting) could occur at locations of repeated relative motion of mechanical
 
component bolted joints. Wear of bolted joint components is generally not a concern; however, for license renewal purposes, wear is being assumed as a potential mechanism for "critical
 
bolting applications." "Critical bolting applications" constitute reactor coolant pressure boundary
 
components where closure bolting failure could result in loss of reactor coolant and jeopardize
 
safe operation of the plant. Loss of material function due to wear is managed by the Bolting
 
Integrity Program. This program specifies inspection requirements in accordance with ASME Code Section XI and recommendations of EPRI NP-5769. These inspection requirements
 
include visual inspections looking for wear as well as for cracks, corrosion, and physical
 
damage on the surface.
Based on the above information provided by the applicant, the staff's concern described in RAI 3.4-5 is resolved.
In RAI 3.4-6, dated November 18, 2004, the staff stated that in LRA Table 3.4.2.2, aluminum-alloy fittings and piping in a treated-water (internal) environment are identified as
 
being susceptible to crack initiation/growth due to SCC and loss of material due to crevice, galvanic, and pitting corrosion. Therefore, the staff requested the applicant to explain (1) why
 
loss of material due to general corrosion is not identified as a potential AERM, (2) why FAC is
 
not a concern for the portion of the condensate system that contains single phase fluid with temperatures less than 200 °F, and (3) how the Chemistry Control Program is used to manage the aging effects of the components/material/environment combinations identified above.
In its response, by letter dated December 16, 2004, the applicant stated that as per industry guidance, aluminum and aluminum-based alloys are not susceptible to loss of material due to
 
general corrosion. The applicant also stated that FAC is only associated with carbon and
 
low-alloy steels; therefore, it would not be identified as an aging mechanism for the
 
aluminum-alloy components. Also, the portions of the condensate system that are within the
 
license renewal boundary are the supply lines to the emergency core cooling pumps. These lines contain single phase fluid with temperatures significantly less than 200 °F with only
 
periodic flow. Consequently, erosion/corrosion is not an aging mechanism that must be
 
managed for the period of extended operation in the condensate system.
The applicant stated that the main objective of the Chemistry Control Program is to minimize loss of material due to general, crevice, and pitting corrosion and crack initiation and growth
 
caused by SCC. Corrosion and cracking of aluminum alloys in treated water is managed by 3-272 maintaining oxygen, chlorides, and sulfates within the limits of the Chemistry Control Program.
The specific chemistry limits are the same as the limits used to manage aging of
 
carbon/low-alloy and stainless steel components in a treated-water environment. The applicant
 
stated that the use of the Chemistry Control Program is consistent with industry practice as
 
identified in its past precedence review. The One-Time Inspection Program is used to verify the
 
Chemistry Control Program's effectiveness.
Based on the above information provided by the applicant, the staff's concern described in RAI 3.4-6 is resolved.
In RAI 3.4-7, dated November 18, 2004, the staff stated that in LRA Table 3.4.2.2, polymer fittings in an inside air (external) or treated-water (internal) environment are not identified with
 
any aging effects. Therefore, the staff requested the applicant to provide a discussion of the air
 
and treated-water environments involved and justify the basis for concluding that there are no
 
aging effects requiring management under such material/environment combinations.
In its response, by letter dated December 16, 2004, the applicant stated that polymer fittings in LRA Table 3.4.2.2 within the condensate system are the insulation couplings between carbon
 
steel and stainless steel pipe, and between aluminum and stainless steel pipe. Acetal (the
 
generic name for a family of polymer products t hat includes DELRIN) provides high strength and stiffness along with increased dimensional stability and ease of machining. The applicant stated
 
that a review of available industry information did not identify any aging effects for DELRIN that
 
would be attributable to the treated-water (internal) environment or the inside air (external)
 
environment.
Based on the above information provided by the applicant, the staff's concern described in RAI 3.4-7 is resolved.
In RAI 3.4-8, dated November 18, 2004, the staff stated that in LRA Table 3.4.2.2, aluminum-alloy fittings in a treated-water (internal) environment are identified as being
 
susceptible to crack initiation/growth due to SCC and loss of material due to crevice and pitting
 
corrosion. Therefore, the staff requested the applicant to explain why loss of material due to
 
general and galvanic corrosion is not identified as a potential AERM during the period of
 
extended operation. The staff also requested the applicant to explain how the Chemistry Control
 
Program, with the association of One-Time Inspection Program, is used to manage the
 
identified aging effects.
In its response, by letter dated December 16, 2004, the applicant stated that as per industry guidance, aluminum and aluminum-based allo ys in a treated-water environment are not susceptible to loss of material due to general corrosion. In addition, the applicant stated that the
 
aluminum valves listed in LRA Table 3.4.2.2 as being within the condensate system are not in contact with more cathodic materials. Therefore, galvanic corrosion is not a concern for
 
aluminum valves in a treated-water environment for the condensate system.
The applicant also stated that the main objective of the Chemistry Control Program is to minimize loss of material due to general, crevice, and pitting corrosion and crack initiation and
 
growth caused by SCC. Corrosion and cracking of aluminum alloys in treated water is managed
 
by maintaining oxygen, chlorides, and sulfates within the limits of the Chemistry Control
 
Program. The specific chemistry limits are t he same as the limits used to manage aging of 3-273 carbon/low-alloy and stainless steel components in a treated-water environment. The applicant stated that the use of the Chemistry Control Program is consistent with industry practice as
 
identified in its past precedence review. The One-Time Inspection program is used to verify the
 
Chemistry Control Program's effectiv eness as recommended by the GALL Report.
After evaluating the applicant's identification of aging effects for each of the above components, the staff evaluated the AMPs to determine whether they are appropriate for managing the
 
identified aging effects. The staff also determined that the UFSAR Supplement contains an
 
adequate description of the program.
Based on the above information provided by the applicant, the staff's concern described in RAI 3.4-8 is resolved.
In RAI 3.4-9, dated November 18, 2004, the staff stated that in LRA Table 3.4.2.3, stainless steel fittings, piping, valves, and restricting orifices forming the reactor coolant pressure
 
boundary (RCPB) in an air/gas (internal), moist air environment are identified as being
 
susceptible to crack initiation/growth due to SCC and loss of material due to crevice and pitting
 
corrosion. Also, CASS valves in an RCPB in an air/gas (internal), moist air environment are
 
identified as susceptible to change in material properties/reduction in fracture toughness due to
 
thermal aging. The One-Time Inspection Program is credited to manage the identified aging
 
effects. Therefore, the staff requested the applicant to provide justification that the One-Time
 
Inspection Program alone, in lieu of a more appropriate periodic inspection program, should be
 
used to manage the identified aging effects for the above-mentioned components and
 
material/environment combinations.
In its response, by letter dated December 16, 2004, the applicant stated that the stainless steel reactor coolant pressure boundary components in Table 3.4.2.3, for the feedwater system, are
 
exposed to an air/gas environment when air is trapped in the vessel flange leak detection line
 
when the vessel head is secured. The air/gas environment is considered moist air because the
 
trapped air is not dried and there is a small potential for leakage. The aging effects are
 
conservatively identified as a moist air environment.
The applicant stated that fittings are addressed in rows 19 and 20 of LRA Table 3.4.2.3. TheAMPs identified for cracking are the ASME Section XI Subsections IWB, IWC, and IWD
 
Inservice Inspection Program and the One-Time Inspection Program. The applicant stated that
 
these same aging effects and AMPs should be shown for each applicable component (i.e.,
piping in rows 40 and 41, and restricting orifices in line item 46). Because of that, line item 46 in
 
the table should be replaced by two line items with aging effects/mechanisms and AMPs similar to those in rows 40 and 41. Valves are addressed in rows 68 and 69. The BWR Stress
 
Corrosion Cracking Program, instead of the One-Time Inspection Program, is the appropriate
 
AMP for the cracking aging effect of stainless steel RCPB valves in line item 68, which should
 
be corrected accordingly. For the cracking aging effect for piping components less than 4 inches
 
NPS, GALL Report Item IV.C1.1-I states, "a plant-specific destructive examination or a
 
nondestructive examination (NDE) that permits inspection of the inside surfaces of the piping is
 
to be conducted to ensure that cracking has not occurred and the component intended function
 
will be maintained during the extended period of operation." The applicant has included this
 
small bore piping inspection in the One-Time Inspection Program.
3-274 For loss of material due to crevice and pitting corrosion, the One-Time Inspection Program is credited as an AMP because corrosion is not expected to occur for the stainless steel
 
components in an air/gas (internal) with moist air environment. The piping is not subject to
 
condensation and is dry except for the abnormal case when reactor vessel flange leakage
 
occurs. The applicant stated that any water that is introduced to this line is reactor grade treated
 
water and, as such, has minimal potential for corrosion.
The applicant stated that thermal aging of CASS valves is addressed in line item 67, where anincorrect AMP was identified. The correct AMP is the ASME Section XI Subsection IWB, IWC, and IWD Inservice Inspection Program. Therefore, line item 67 should be corrected accordingly.
Based on the above updated information, the staff considered that the applicant had adequately addressed its concern regarding the use of the One-Time Inspection Program as the sole AMP
 
for the identified aging effects. Therefore, the staff's concern described in RAI 3.4-9 is resolved.
3.4.2.3.1  Main Steam System - Summary of Aging Management Evaluation - Table 3.4.2.1 The staff reviewed LRA Table 3.4.2.1, which summarizes the results of AMR evaluations for the main steam system component groups.
In LRA Table 3.4.2.1, the applicant identified no aging effects for stainless steel and carbon and low-alloy steel components exposed to air, for piping and tubing component types. Air is not
 
identified in the GALL Report as an environment for these components and materials.
On the basis of current industry research and operating experience, dry air on metal will not result in aging that will be of concern during the period of extended operation. The external
 
environments being referred to are typical of ambient air (e.g., under a shelter, indoor, or
 
air-conditioned enclosure or room). Therefore, the staff concluded that there are no aging
 
effects requiring management for stainless steel in an air environment.
In LRA Table 3.4.2.1, the applicant identified no aging effects for carbon and low-alloy steel condenser components. No aging effects were identified by the AMR for the main condenser
 
components made of carbon steel, or stainless st eel in a treated-water environment or inside air. These materials have successfully performed as main condenser materials at other plants.
 
Further, the applicant concluded that aging management of the main condenser is not required
 
based on analysis of materials, environments, and aging effects. Condenser integrity required to
 
perform the post-accident intended function (holdup and plateout of main steam isolation valve (MSIV) leakage) is continuously confirmed by normal plant operation. The main condenser must
 
perform a significant pressure boundary function (maintain vacuum) to allow continued plant
 
operation. For these reasons, the applicant has not identified any applicable aging effects for
 
the main condenser. The staff concurred with the applicant's conclusion because the main
 
condenser integrity is continuously confirmed during normal plant operation and, thus, the
 
condenser post-accident function will be ensured.
3.4.2.3.2  Condensate and Demineralized Water System - Summary of Aging Management Evaluation - Table 3.4.2.2 The staff reviewed LRA Table 3.4.2.2, which summarizes the results of AMR evaluations for the condensate and demineralized water system component groups.
3-275 In LRA Table 3.4.2.2, the applicant identified no aging effects for stainless, carbon, and low-alloy steel components exposed to air for piping and tubing component types. Air is not
 
identified in the GALL Report as an environment for these components and materials.
On the basis of current industry research and operating experience, dry air on metal will not result in aging that will be of concern during the period of extended operation. Therefore, the
 
staff concluded that there are no AERMS for stainless, carbon, and low-alloy steel in an air
 
environment.
In LRA Table 3.4.2.2, the applicant identified an aging effect of galvanic corrosion for carbon and low-alloy steel components exposed to treated water internally. The GALL Report does not
 
indicate the aging effect, but recommends further evaluation for these components.
In managing the galvanic aging effect, the applicant stated that galvanic corrosion can only progress if the dissimilar metals are in contact in the presence of an electrolyte. Control of
 
galvanic corrosion in treated water systems is possible by maintaining adequate chemistry controls. As treated water is a poor electrolyte, the dissimilar metals in this environment would
 
experience little or no galvanic corrosion. This is evidenced by the lack of industry operating experience of galvanic corrosion failures in treated water systems. A review of BFN PERs and
 
work orders did not identify instances where galvanic corrosion was a failure mechanism.
The staff found that the applicant demonstrated that the effects of aging for loss of material due to galvanic corrosion will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB during the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
In LRA Table 3.4.2.2, aluminum-alloy fittings in a treated-water environment are identified as being susceptible to crack initiation/growth due to SCC and loss of material due to crevice, galvanic, and pitting corrosion. Since this material was not listed in the GALL Report, the staff
 
needed some additional explanation to justify the Chemistry Control Program and One-Time
 
Inspection Program to manage the effect.
The applicant stated that the aging effects identified for aluminum alloys are consistent with EPRI Report 1003056, "Non-Class 1 Mechanical Implementation Guideline and Mechanical
 
Tools, Revision 3." Aluminum alloys were evaluated using the guidelines given in the report.
 
BFN utilizes the Chemistry Control Program and One-Time Inspection Program to manage the effect, which is also the industry standard; based on past precedents review of similar
 
applications for managing the aging effects of aluminum alloys in treated-water environments, the staff found the response acceptable.
In LRA Table 3.4.2.2, for carbon and low-alloy steel piping in air/gas environment (internal) the applicant mentions only one-time inspection for aging management due to general corrosion.
 
GALL Table VIII.E.1, Condensate System, does not address the air/gas environment identified in the LRA.
The applicant clarified that the row 35 environment in LRA Table 3.4.2.2 referred to the area between the two isolation valves on condensate sy stem vents and drains. This small segment of piping is exposed to condensate flow when the valves are open and has air trapped with varying
 
amount of condensate based on how the valves are closed, that is, the sequence and time 3-276 between valve closings. The safety consequences for this short segment of piping failing are non-existent, because this line is downstream of a closed isolation valve. However, for
 
completeness and to verify that these lines are not degrading, the applicant will perform some
 
inspections using the One-Time Inspection Program, even though the GALL Report does not
 
address the air/gas environment.
3.4.2.3.3  Feedwater System - Summary of Aging Management Evaluation - Table 3.4.2.3 The staff reviewed LRA Table 3.4.2.3, which summarizes the results of AMR evaluations for the feedwater system component groups.
In LRA Table 3.4.2.3, stainless steel fittings (item 11) in a treated water environment are identified as being susceptible to crack initiation and SCC, which is not identified in GALL
 
Report (VIIID2.1.1-b) for this item.
The applicant stated in Mechanical Evaluation Report - Feedwater System 003 that the shape of components in this system made from stainless steel material may present a high stress
 
environment, and the treated water may contain contaminants such as chlorides and sulfides.
This combination, with temperatures above 140 °F, may promote SCC. This conclusion is
 
supported by evidence from industry experience. The staff concurred with the applicant that this
 
aging effect needed appropriate evaluation and managing. The staff agreed that the proposed
 
management through the Chemistry Control Progr am and One-Time Inspection Program will be adequate to manage the aging.
 
====3.4.3 Conclusion====
The staff concluded that the applicant had provided sufficient information to demonstrate that the effects of aging for the steam and power conv ersion system components that are within the scope of license renewal and subject to an AMR will be adequately managed so that the
 
intended function(s) will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
The staff also reviewed the applicable UFSAR supplement program summaries and concluded that they adequately describe the AMPs credited for managing aging of the steam and power
 
conversion system, as required by 10 CFR 54.21(d).
 
===3.5 Aging===
Management of Containments, Structures, and Component Supports This section of the SER documents the staff's review of the applicant's AMR results for the containments, structures, and component supports components and component groups
 
associated with the following systems:
* primary containment structures
* reactor buildings
* equipment access lock
* diesel generator buildings
* standby gas treatment building
* off-gas treatment building
* vacuum pipe building 3-277
* residual heat removal service water tunnels
* electrical cable tunnel from intake pumping station to the powerhouse
* underground concrete encased structures
* earth berm
* intake pumping station
* gate structure No. 3
* intake channel
* north bank of cool water channel east of gate structure No. 2
* south dike of cool water channel between gate structure Nos. 2 and 3
* condensate water storage tanks' foundations and trenches
* containment atmosphere dilution storage tanks' foundations
* reinforced concrete chimney
* turbine buildings
* diesel high-pressure fire pump house
* vent vaults
* transformer yard
* 161 kV (kiloVolt) switchyard
* 500 kV switchyard
* structures and component supports commodities group3.5.1  Summary of Technical Information in the Application In LRA Section 3.5, the applicant provided AMR results for components. In LRA Table 3.5.1,"Summary of Aging Management Evaluations for Structures and Component Supports
 
Evaluated in Chapter II and III of NUREG-1801," the applicant provided a summary comparison
 
of its AMRs with the AMRs evaluated in the GALL Report for the containments, structures, and
 
component supports components and component groups.
The applicant's AMRs incorporated applicable operating experience in the determination of the AERM. These reviews included evaluation of plant-specific and industry operating experience.
 
The plant-specific evaluation included reviews of condition reports and discussions with
 
appropriate site personnel to identify the AERM. The applicant's review of industry operating
 
experience included a review of the GALL Report and operating experience issues identified
 
since the issuance of the GALL Report.
 
====3.5.2 Staff====
Evaluation The staff reviewed LRA Section 3.5 to determine whether the applicant had provided sufficient information to demonstrate that the effects of aging for the containments, structures, and
 
component supports components that are within the scope of license renewal and subject to an
 
AMR will be adequately managed so that the intended functions will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
During the weeks of June 21 and July 26, 2004, the staff performed an onsite audit, of AMRs to confirm the applicant's claim that certain identified AMRs are consistent with the GALL matters
 
described in the GALL Report. The staff verified that the material presented in the LRA is
 
applicable and that the applicant had identified the appropriate GALL AMRs. The staff's
 
evaluations of the AMPs are documented in SER Section 3.0.3. Detail of the staff's audit 3-278 evaluation are documented in the BFN audit and review report, and are summarized in SER Section 3.5.2.1.
In the onsite audit, the staff also selected AMRs that are consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further
 
evaluations are consistent with the acceptance criteria in SRP-LR Section 3.5.2.2, dated
 
July 2001. The staff's audit evaluations are documented in the BFN audit and review report, and
 
are summarized in SER Section 3.5.2.2.
In the onsite audit, the staff also conducted a technical review of the remaining AMRs that are not consistent with, or not addressed in, the GALL Report. The audit and technical review
 
included evaluating whether all plausible aging effects had been identified and evaluating
 
whether the aging effects listed are appropriate for the combination of materials and
 
environments specified. The staff's audit evaluations are documented in the BFN audit and
 
review report, and are summarized in SER Section 3.5.2.3. The staff's evaluation of its technical
 
review is also documented in SER Section 3.5.2.3.
Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or
 
monitoring aging for the containments, structures, and component supports components.
Table 3.5-1 below provides a summary of the staff's evaluation of components, aging effects/mechanisms, and AMPs listed in LRA Section 3.5 that are addressed in the GALL
 
Report.Table 3.5-1  Staff Evaluation for Containments, Structures, and Component Supports in the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation Penetration sleeves,penetration bellows, and dissimilar metal welds (Item Number
 
3.5.1.1)Cumulative fatigue damageTLAA evaluated inaccordance with 10 CFR 54.21(c)TLAAThis TLAA is evaluated in
 
Section 4.6, Primary
 
Containment Fatigue Penetration sleeves,bellows, and
 
dissimilar metal welds (Item Number
 
3.5.1.2)Cracking due tocyclic loading, crack initiation and growth
 
due to SCC Containment Inservice Inspection (ISI) Program;
 
Containment Leak Rate Test Program Containment ISI Program; Containment Leak Rate Test ProgramConsistent withGALL, with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.5.2.1)Penetration sleeves,penetration bellows, and dissimilar metal welds (Item Number
 
3.5.1.3)Loss of material due to corrosion Containment ISI Program; Containment Leak Rate Test Program Containment ISI Program; Containment Leak Rate Test ProgramConsistent withGALL, which
 
recommends no
 
further evaluation (See Section
 
3.5.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-279 Personnel airlock and equipment
 
hatch (Item Number
 
3.5.1.4)Loss of material due to corrosion Containment ISI Program; Containment Leak Rate Test Program Containment ISI Program; Containment Leak Rate Test ProgramConsistent withGALL, which
 
recommends no
 
further evaluation (See Section
 
3.5.2.1)Personnel airlock and equipment
 
hatch (Item Number
 
3.5.1.5)Loss of leak tightness in closed
 
position due to mechanical wear of
 
locks, hinges, and
 
closure mechanisms Containment LeakRate Test Program; Plant Technical
 
Specifications
 
Program Containment LeakRate Test Program; Plant Technical
 
Specifications
 
ProgramConsistent withGALL, which
 
recommends no
 
further evaluation (See Section
 
3.5.2.1)Seals, gaskets, and moisture barriers (Item Number
 
3.5.1.6)Loss of sealant and leakage through
 
containment due to
 
deterioration of joint
 
seals gaskets, and
 
moisture barriers Containment ISI Program; Containment Leak Rate Test Program Containment ISI Program; Containment Leak Rate Test ProgramConsistent withGALL, which
 
recommends no
 
further evaluation (See Section
 
3.5.2.1)Concrete elements:
foundation, dome, and wall (Item Number
 
3.5.1.7)Aging of accessible and inaccessible
 
concrete areas due
 
to leaching of calcium hydroxide, aggressive chemical
 
attack, and
 
corrosion of
 
embedded steel Containment ISI ProgramN/ANot applicableBFN has a Mark I
 
steel containment Concrete elements:
foundation (Item Number
 
3.5.1.8)Cracks, distortion, and increases in
 
components stress
 
level due to
 
settlement Structures Monitoring ProgramN/ANot applicableBFN has a Mark I
 
steel containment Concrete elements:
foundation (Item Number
 
3.5.1.9)Reduction in foundation strength
 
due to erosion of
 
porous concrete
 
subfoundation Structures Monitoring ProgramN/ANot applicableBFN has a Mark I
 
steel containment Concrete elements:
foundation, dome, and wall (Item Number
 
3.5.1.10)Reduction of strength and
 
modulus due to
 
elevated temperature)Plant-specificN/ANot applicableBFN has a Mark I
 
steel containment Prestressed containment:
 
tendons and
 
anchorage components (Item Number
 
3.5.1.11)Loss of prestress due to relaxation, shrinkage, creep, and elevated
 
temperatureTLAA evaluated inaccordance with 10 CFR 54.21(c)TLAANot applicableBFN has a Mark I
 
steel containment
 
and not prestressed concrete with
 
tendons Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-280 Steel elements: liner plate, containment
 
shell (Item Number
 
3.5.1.12)Loss of material due to corrosion in
 
accessible and
 
inaccessible areas Containment ISI Program; Containment Leak Rate Test Program Containment ISI Program; Containment Leak Rate Test ProgramConsistent withGALL which
 
recommends further
 
evaluation (See
 
Section 3.5.2.1)
Steel elements: ventheader, drywell
 
head, torus, downcomers, and
 
pool sheel (Item Number
 
3.5.1.13)Cumulative fatigue damage (CLB fatigue analysis
 
exists)TLAA evaluated inaccordance with 10 CFR 54.21(c)TLAAThis TLAA is evaluated in
 
Section 4.6, Primary
 
Containment Fatigue Steel elements:protected by coating (Item Number
 
3.5.1.14)Loss of material due to corrosion in
 
accessible areas
 
only Protective Coating Monitoring and
 
Maintenance
 
ProgramN/ANot applicableBFN does not credit
 
coatings to prevent
 
general corrosion Prestressed containment:
 
tendons and
 
anchorage components (Item Number
 
3.5.1.15)Loss of material due to corrosion of
 
prestressing
 
tendons and
 
anchorage components Containment ISI ProgramN/ANot applicableBFN has a Mark I
 
steel containment
 
and not prestressed concrete with
 
tendons Concrete elements:
foundation, dome, and wall (Item Number
 
3.5.1.16)Scaling, cracking, and spalling due to freeze-thaw;
 
expansion and
 
cracking due to reaction with
 
aggregate Containment ISI ProgramN/ANot applicableBFN has a Mark I
 
steel containment Steel elements: ventline bellows, vent
 
headers, and downcomers (Item Number
 
3.5.1.17)Cracking due tocyclic loads; crack initiation and growth
 
due to SCC Containment ISI Program; Containment Leak Rate Test Program Containment ISI Program; Containment Leak Rate Test ProgramConsistent withGALL, which
 
recommends further
 
evaluation (See
 
3.5.2.1)Steel elements:
suppression
 
chamber liner (Item Number
 
3.5.1.18)Crack initiation andgrowth due to SCC Containment ISI Program; Containment Leak Rate Test Program Containment ISI Program; Containment Leak Rate Test ProgramConsistent withGALL, with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.5.2.1)Steel elements:drywell head and downcomer pipes (Item Number
 
3.5.1.19)Fretting and lock updue to wear Containment ISI Program Containment ISI ProgramConsistent withGALL, with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.5.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-281 All Groups except Group 6: accessible interior/exterior
 
concrete and steel
 
components (Item Number
 
3.5.1.20)All types of aging effects Structures Monitoring Program Structures Monitoring ProgramConsistent withGALL, which
 
recommends further
 
evaluation (See
 
Section 3.5.2.1)
Groups 1-3, 5, 7-9:
inaccessible
 
concrete components, such as exterior walls below grade and
 
foundation (Item Number
 
3.5.1.21)Aging of inaccessible
 
concrete areas due
 
to aggressive
 
chemical attack, and corrosion of
 
embedded steelPlant-specificConsistent withGALL, which
 
recommends further
 
evaluation if an
 
aggressive below-grade
 
environment exists (See Section
 
3.5.2.2.1)
Group 6: all accessible/
 
inaccessible
 
concrete, steel, and
 
earthen components (Item Number
 
3.5.1.22)All types of aging effects, including
 
loss of material due
 
to abrasion, cavitation, and
 
corrosion Inspection of Water-Control
 
Structures;
 
FERC/US Army
 
Corps of Engineers
 
Dam Inspection and
 
Maintenance
 
Program Inspection of Water-Control
 
Structures;
 
FERC/US Army
 
Corps of Engineers
 
Dam Inspection and
 
Maintenance
 
ProgramConsistent withGALL which
 
recommends further
 
evaluation (See
 
Section 3.5.2.2.8)
Group 5: liners (Item Number
 
3.5.1.23)Crack initiation andgrowth due to SCC;
 
loss of material due
 
to crevice corrosionChemistry Control Program; Monitoring of Spent Fuel Pool Water Level
 
ProgramChemistry Control Program; Monitoring of Spent Fuel Pool Water Level
 
ProgramConsistent withGALL, with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.5.2.1)Groups 1-3, 5, 6: allmasonry block walls (Item Number
 
3.5.1.24)Cracking due to restraint, shrinkage, creep, and
 
aggressive
 
environmentMasonry Wall ProgramMasonry Wall ProgramConsistent withGALL, which
 
recommends no
 
further evaluation (See Section
 
3.5.2.1)Groups 1-3, 5, 7-9:
foundation (Item Number
 
3.5.1.25)Cracks, distortion, and increases in
 
component stress
 
level due to
 
settlement Structures Monitoring Program Structures Monitoring ProgramConsistent withGALL, which
 
recommends further
 
evaluation (See
 
Section 3.5.2.2.2)
Groups 1-3, 5-9:
foundation (Item Number
 
3.5.1.26)Reduction in foundation strength
 
due to erosion of
 
porous concrete
 
subfoundation Structures Monitoring ProgramN/ANot applicableBFN does not use
 
porous concrete
 
subfoundations Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-282 Groups 1-5:
concrete (Item Number
 
3.5.1.27)Reduction of strength and
 
modulus due to
 
elevated temperaturePlant-specificStructures Monitoring ProgramConsistent withGALL, which
 
recommends further
 
evaluation (See
 
Section 3.5.2.2.3)
Groups 4, 8: liners (Item Number
 
3.5.1.28)Crack initiation andgrowth due to SCC;
 
loss of material due
 
to crevice corrosionPlant-specificN/ANot applicableBFN does not have any Group 7
 
structues BFN does not have
 
in-scope stainless
 
steel liners in an
 
exposed-to-fluid
 
environment for any
 
Group 8 structure All groups: support members, anchor
 
bolts, concrete
 
surrounding anchor bolts, welds, grout
 
pad, bolted
 
connections, etc.
(Item Number
 
3.5.1.29)Aging of component supports Structures Monitoring Program Structures Monitoring ProgramConsistent withGALL, which
 
recommends no
 
further evaluation if within the scope of
 
the applicant's
 
Structures
 
Monitoring Program (See Section 3.5.2.1)
Groups B1.1, B1.2, and B1.3: support
 
members, anchor bolts, and welds (Item Number
 
3.5.1.30)Cumulative fatigue damage (CLB fatigue analysis
 
exists)TLAA evaluated inaccordance with 10 CFR 54.21(c)TLAAThis TLAA is evaluated in
 
Section 4.6, Primary
 
Containment Fatigue Groups B1.1, B1.2, and B1.3: support
 
members, anchor bolts, welds, spring
 
hangers, guides, stops, and vibration
 
isolators (Item Number
 
3.5.1.32)Loss of material due to environmental
 
corrosion; loss of
 
mechanical function
 
due to corrosion, distortion, dirt, overload, etc.ISI ProgramISI ProgramConsistent withGALL, which
 
recommends no
 
further evaluation (See Section
 
3.5.2.1)Group B1.1:
high-strength low-alloy bolts (Item Number
 
3.5.1.33)Crack initiation andgrowth due to SCC Bolting integrity Program Exception to GALL (See Section
 
3.5.2.3.26)
The staff's review of the BFN component groups followed one of several approaches. One approach, documented in SER Section 3.5.2.1, involves the staff's review of the AMR results for
 
components in the containments, structures, and component supports that the applicant 3-283 indicated are consistent with the GALL Report and do not require further evaluation. Another approach, documented in SER Section 3.5.2.2, involves the staff's review of the AMR results for
 
components in the containments, structures, and component supports that the applicant
 
indicated are consistent with the GALL Report and for which further evaluation is recommended.
 
A third approach, documented in SER Section 3.5.2.3, involves the staff's review of the AMR
 
results for components in the containments, structures, and component supports that the
 
applicant indicated are not consistent with, or not addressed in, the GALL Report. The staff's
 
review of AMPs that are credited to manage or monitor aging effects of the containments, structures, and component supports components is documented in SER Section 3.0.3.3.5.2.1  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Not Recommended Summary of Technical Information in the Application. In LRA Section 3.5.2.1, the applicant identified the materials, environments, and aging effects requiring management. The applicant
 
identified the following programs that manage the aging effects related to the containments, structures, and component supports components:
* 10 CFR 50 Appendix J Program
* ASME Section XI Subsection IWE Program
* Structures Monitoring Program
* Chemistry Control Program
* Fire Protection Program
* Masonry Wall Program
* Inspection of Water-Control Structures Program
* ASME Section XI Subsection IWF Program
* One-Time Inspection Program Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant has claimed consistency with the GALL Report, and for which the GALL Report does not
 
recommend further evaluation, the staff performed an audit and review to determine whether the
 
plant-specific components contained in these GALL Report component groups were bounded
 
by the GALL Report evaluation.
The applicant provided a note for each AMR line item. The notes described how the information in the tables aligns with the information in the GALL Report. The staff audited those AMRs with
 
Notes A through E, which indicated that the AMR was consistent with the GALL Report.
Note A indicated that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the AMP
 
identified in the GALL Report. The staff audited these line items to verify consistency with the
 
GALL Report and the validity of the AMR for the site-specific conditions.
Note B indicated that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP
 
identified in the GALL Report. The staff audited these line items to verify consistency with the
 
GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been
 
reviewed and accepted by the staff. The staff also determined whether the AMP identified by the 3-284 applicant was consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site-specific conditions.
Note C indicated that the component for the AMR line item is different from but consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent
 
with the AMP identified by the GALL Report. This note indicates that the applicant had not been
 
able to find a listing of some system components in the GALL Report. However, the applicant
 
identified a different component in the GALL Report that had the same material, environment, aging effect, and AMP as the component that was under review. The staff audited these line
 
items to verify consistency with the GALL Report. The staff also determined whether the AMR
 
line item of the different component was applicable to the component under review and whether
 
the AMR was valid for the site-specific conditions.
Note D indicated that the component for the AMR line item is different from but consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some
 
exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify
 
consistency with the GALL Report. The staff verified whether the AMR line item of the different
 
component was applicable to the component under review. The staff verified whether the
 
identified exceptions to the GALL AMPs had been reviewed and accepted by the staff. The staff
 
also determined whether the AMP identified by the applicant is consistent with the AMP
 
identified in the GALL Report and whether the AMR is valid for the site-specific conditions.
Note E indicated that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited. The staff audited these line items
 
to verify consistency with the GALL Report. The staff also determined whether the identified
 
AMP would manage the aging effect consistent with the AMP identified by the GALL Report and
 
whether the AMR is valid for the site-specific conditions.
The staff conducted an audit and review of the information provided in the LRA, as documented in the BFN audit and review report. The staff did not repeat its review of the matters described in
 
the GALL Report. However, the staff did verify that the material presented in the LRA was
 
applicable and that the applicant had identified the appropriate GALL Report AMRs. The staff's
 
evaluation is discussed below.
For aging management evaluations that the applicant stated are consistent with the GALL Report and for which further evaluation is not recommended, the staff conducted its review and
 
audit to determine if the applicant's reference to the GALL Report in the LRA is acceptable.
The staff determined that the applicant had: (1) provided a brief description of the system, components, materials, and environment; (2) stated that the applicable aging effects have been
 
reviewed and are evaluated in the GALL Report; and (3) identified those aging effects for the
 
SCs that are subject to an AMR. The staff also determined that the LRA line item is consistent
 
with the GALL Report Volume 2 system t ables line item for component type and MEAP.
To confirm consistency with the GALL Report, during the onsite audit in the weeks of June 21 and July 26, 2004, the staff requested the applicant to clarify the following LRA line items:
In LRA Table 3.5.2.1, the applicant credits the 10 CFR Part 50, Appendix J Program for some structures and component supports in the primary containment. The GALL Report is also based 3-285 on an expectation that plant technical specifications will be credited. The staff requested the applicant to identify these items and explain the BFN plant technical specifications that govern
 
the leakage testing of these items after each opening.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that Table 3.5.2.1, rows 4 and 6 apply to the drywell personnel access airlock. Table 3.5.2.1, rows 8 and 10, apply to the torus and drywell access hatches and equipment hatches. These
 
containment pressure boundary components will continue to be inspected consistent with the
 
CLB Technical Specifications for Appendix J requirements. BFN Technical Specification
 
Requirements, Section 5.5.12, "Primary Cont ainment Leakage Rate Testing Program," provides the requirement to establish a program to implement the leakage rate testing of the containment
 
as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, and provides the leakage rate
 
acceptance criteria of the program. With these clarifications, the staff concluded that these
 
items are consistent with the GALL Report.
In reference to LRA Table 3.5.2.1, the staff further requested the applicant to identify the caulking and sealants included under this item and clarify why Appendix J is not a credited
 
AMP. By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that Table 3.5.2.1 applies to the moisture barrier seal between the drywell steel shell and
 
the concrete floor in the bottom of the drywell, elevation 549.92 feet. Appendix J testing is not
 
required, since the drywell floor moisture barrier seal between drywell steel shell and the
 
549.92-foot elevation concrete does not have a pressure boundary function. The staff concurred
 
with the applicant's explanation and found this acceptable.
In LRA Table 3.5.2.2, the staff observed that the AMP referenced for spent fuel pool liners is not consistent with GALL Report Item III.A5.2-b. The Chemistry Control Program is referenced.
 
However, the GALL Report also includes "monitoring of the spent fuel pool level." The staff
 
requested that the applicant provide the technical basis for this omission. By letter dated
 
October 8, 2004, the applicant submitted its formal response to the staff, stating that the AMP
 
section for LRA Table 3.5.2.2 should have identified that the spent fuel pool level is monitored
 
by plant operations. Browns Ferry will submit a change to correct this omission. With this correction, the staff concluded that the applicant's AMR is consistent with the GALL Report.
In reference to LRA Table 3.5.2.2, the staff also requested the applicant to describe the AMR for Boral and to clarify whether stainless steel components are used to support the Boral. If the
 
AMR supports the conclusion that Boral does not require aging management, but the stainless
 
steel supports do, then the Chemistry Control Program would be an acceptable AMP for this
 
item. If not, the applicant was requested to provide the technical basis for crediting the
 
Chemistry Control Program as the appropriate AMP for Boral.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the Boral core is made up of a central segment of a dispersion of boron carbide in
 
aluminum. This central segment is clad on both sides with aluminum to form a plate. The Boral plates are sandwiched between two stainless steel plates which are closure-welded form the
 
container. Vent holes have been added to prevent the buildup of hydrogen gas between the
 
stainless steel containers. If the stainless steel containers remain intact, the Boral core will be
 
unaffected and will retain its neutron-absorbing capacity. The Chemistry Control Program will
 
manage aging of the stainless steel containers. With these clarifications, the staff concluded
 
that this item is consistent with the GALL Report.
3-286 In reference to LRA Tables 3.5.2.12, 3.5.2.13, and 3.5.2.26, the staff requested that the applicant identify each of the components included and explain the reference to Note C (Component is different from, but consistent wi th, GALL Report item for material, environment, and aging effect. The AMP is consistent with the GALL Report).
In its response, by letter dated October 8, 2004, the applicant stated that Table 3.5.2.1.12, rows 41 and 42, apply to security barrier steel framing at the intake pumping station. Note C was
 
used because the security barrier steel framing was evaluated with structural steel beams
 
columns, and trusses (steel components) commodity group. Table 3.5.2.13, rows 4, 5, 6, 7, and
 
8, apply to concrete that is sandwiched between the steel sheet pile cells of Gate Structure
 
Number 3. Note C was used because the concrete sandwiched between the steel sheet pile
 
cells was evaluated with concrete elements that were not sandwiched between steel sheet
 
piles. Table 3.5.2.26, rows 19 and 20, apply to cable trays and supports in containment
 
atmosphere and inside air environments. Note C was used because cable trays were evaluated
 
with the cable tray supports. With these clarifications, the staff concluded that these items are
 
consistent with the GALL Report.
In reference to LRA Table 3.5.2.12, the staff requested the applicant to explain the extent to which the referenced submerged structures are inspected for the effects of freeze-thaw under
 
the Inspection of Water-Control Structures Program. By letter dated October 8, 2004, the
 
applicant submitted its formal response to the staff, stating that the referenced submerged
 
structure will be inspected for the effects of freeze-thaw at the waterline where icing conditions
 
could occur. The staff concluded that the applicant's approach to the management of this aging
 
effect is consistent with the GALL Report.
On the basis of its audit, the staff determined that, for AMRs not requiring further evaluation, as identified in LRA Table 3.5.1 (Table 1), the applicant's references to the GALL Report are
 
acceptable, that the line items are consistent with the GALL Report, and no further staff review
 
is required.
Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating
 
experience and proposals for managing associated aging effects. On the basis of its review, the
 
staff concluded that the AMR results, that the applicant claimed to be consistent with the GALL
 
Report are consistent with the AMRs in the GALL Report. Therefore, the staff concluded that the
 
applicant had demonstrated that the effects of aging for these components will be adequately
 
managed so that their intended function(s) will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR54.21(a)(3).3.5.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended Summary of Technical Information in the Application. In LRA Section 3.5.2.2, the applicant provided further evaluation of aging management as recommended by the GALL Report for the containments, structures, and component supports. The applicant provided information
 
concerning how it will manage the following aging effects:
* aging of inaccessible concrete areas 3-287
* cracking, distortion, and increase in component stress level due to settlement; reduction of foundation strength due to erosion of porous concrete subfoundations, if not covered
 
by Structures Monitoring Program
* reduction of strength and modulus of concrete structures due to elevated temperature
* loss of material due to corrosion in inaccessible areas of steel containment shell or liner plate
* loss of prestress due to relaxation, shrinkage, creep, and elevated temperature
* cumulative fatigue damage
* cracking due to cyclic loading and stress corrosion cracking
* aging of structures not covered by Structures Monitoring Program
* aging management of inaccessible areas
* aging of supports not covered by Structures Monitoring Program
* cumulative fatigue damage due to cyclic loading
* quality assurance for aging management of non-safety-related components Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report recommends further
 
evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it had
 
adequately addressed the issues that were further evaluated. In addition, the staff reviewed the
 
applicant's further evaluations against the criteria contained in SRP-LR Section 3.5.2.2. Details
 
of the staff's audit are documented in the staff's BFN audit and review report. The staff's
 
evaluation of the aging effects is discussed in the following sections.
3.5.2.2.1  Aging of Inaccessible Concrete Areas
 
The discussion in SRP-LR Section 3.5.2.2.1.1 is not applicable to BFN since BFN is a BWR with a Mark I steel containment.
3.5.2.2.2  Cracking, Distortion, and Increase in Component Stress Level Due to Settlement; Reduction of Foundation Strength due to Erosion of Porous Concrete Subfoundations, if Not
 
Covered by Structures Monitoring Program The discussion in SRP-LR Section 3.5.2.2.1.2 is not applicable to BFN since BFN is a BWR with a Mark I steel containment.
3.5.2.2.3  Reduction of Strength and Modulus of Concrete Structures due to Elevated Temperature The discussion in SRP-LR Section 3.5.2.2.1.3 is not applicable to BFN since BFN is a BWR with a Mark steel containment.
3-288 3.5.2.2.4  Loss of Material due to Corrosion in Inaccessible Areas of Steel Containment Shell or Liner Plate The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP-LR Section 3.5.2.2.1.4. In LRA Section 3.5.2.2.1.4, the applicant addressed loss of material due to corrosion in
 
inaccessible areas of steel containment elements.
SRP-LR Section 3.5.2.2.1.4 states that loss of material due to corrosion could occur in inaccessible areas of the steel containment shell or the steel liner plate for all types of PWR and
 
BWR containments. The GALL Report recommends further evaluation of plant-specific
 
programs to manage this aging effect for inaccessible areas if the following specific criteria
 
defined in the GALL Report cannot be satisfied: (1) concrete meeting the requirements of ACI
 
318 or 349 and the guidance of 201.2R was used for the containment concrete in contact with
 
the embedded containment shell or liner; (2) the accessible concrete is monitored to ensure that
 
it is free of penetrating cracks that provide a path for water seepage to the surface of the
 
containment shell or liner; (3) the accessible portion of the moisture barrier, at the junction
 
where the shell or liner becomes embedded, is subject to aging management activities in
 
accordance with IWE requirements; (4) borated water spills and water ponding on the
 
containment concrete floor are not common and when detected are cleaned up in a timely
 
manner.In the LRA, the applicant stated that loss of material due to corrosion in inaccessible areas of steel containment elements is not significant. The drywell steel containment vessel is
 
inaccessible (except for the drywell head) for visual examination from the outside surface. There
 
has been evidence of water leaking from the sand bed drains on both Units 2 and 3. Since there
 
is a horizontal weld connecting the first and second course of drywell liner plates approximately
 
eight inches above the drywell concrete floor, ultrasonic testing (UT) thickness measurements from the drywell floor up to this weld, around the drywell circumference, would conservatively
 
bound the sand pocket area. UT thickness measurements of this area were obtained during the
 
U2C10 and U3C8 refueling outages for Units 2 and 3 respectively and in 1999 and 2002 for
 
Unit 1. The data indicated that the condition of the drywell steel liner plate in this area is good
 
and that this area did not require augmented examination.
The applicant further stated in the LRA that concrete structures and concrete components are designed in accordance with ACI 318-63 and ACI 318-71 and constructed using materials
 
conforming to ACI and ASTM standards. The Structures Monitoring Program monitors the
 
concrete to ensure that it is free of penetrating cracks that provide a path for water seepage to
 
the surface of the containment shell. Research of plant history did not reveal any instances of
 
borated water spills or water ponding on the containment concrete floor. A general visual
 
inspection of the moisture barrier at the junction of the steel drywell shell and the concrete floor is performed once each inspection interval in accordance with the ASME Code Section XI, Subsection IWE Program.
The applicant concluded in the LRA that, since all of the GALL Report further evaluation conditions are satisfied, a plant-specific AMP for corrosion in inaccessible areas (embedded
 
containment steel shell and drywell support skirt) is not required.
During the audit, the staff requested the applicant to provide details of the UT measurements in the sand pocket region for all three units, including comparisons with the original wall 3-289 thicknesses and trending results. The staff also requested the applicant to discuss future planned inspections of steel containment corrosion in the sand pocket region for all three units
 
and the basis for not inspecting other regions of the drywell for all three units in light of the
 
evidence of water leaking from the sand bed drains. It is noted that there is expansion foam in
 
the air gap between the drywell shell and the surrounding concrete that can become wet as a
 
result of the leaking water. Thus, other areas of the drywell shell could be susceptible to
 
corrosion.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that in response to GL 87-05, which addressed the potential for corrosion of BWR Mark I steel
 
drywells in the "sand pocket region," it had provided the staff with the results of the ultrasonic
 
testing for corrosion degradation of drywell liner plate on Aug. 30, 1988. The results of the
 
ultrasonic testing show that each unit's drywell had been ultrasonically tested near the sand
 
cushion area during 1987. The tests showed that the nominal thickness was maintained on
 
each drywell. Below, are the results of each unit's drywell ultrasonic testing. (Note: the following
 
results are quoted from the applicant's letter to the staff dated August 30, 1988.)
* Unit 1- No reading below the nominal thickness of one inch was measured, indicating that the integrity of the drywell liner plate is maintained. Periodic leakage from the sand
 
cushion area has been observed. Corrosive species in the drainage are bases to
 
suspect a higher rate of corrosion on Unit 1 drywell liner plate than on Unit 2 and 3.
 
However, objective evidence of serious corrosion damage was not noted.
* Unit 2 - No reading below the nominal thickness of one inch was measured, indicating that no damage to the integrity of the drywell liner plate has occurred.
* Unit 3 - No reading below the nominal thickness of one inch was measured, indicating that no damage to the integrity of the drywell liner plate has occurred. The applicant further stated that Procedure SPP-9.1, "ASME Section XI," is the applicant's standard to establish administrative controls and provide requirements, standard methods,guidance, and interfaces for preparation of ASME Code Section XI and augmented inservice
 
inspection and testing programs at each nuclear site. In addition, this procedure allows for the
 
control and dissemination of the site programs as stand alone documents, as it is required to
 
meet the individual site-specific requirements resulting from the physical plant differences.
BFN Technical Instruction 0-TI-376, "ASME Section XI Containment Inservice Inspection
 
Program Units 1, 2, and 3," is an administrative technical instruction employed to implement the inservice inspection provisions of SPP-9.1 relative to Class MC components at BFN.
 
Appendix 9.7 to BFN Technical Instruction 0-TI-376 documents the Units 2 and 3 evaluation of
 
Class MC components to determine augmented exam ination requirements in accordance with Table IWE-2500-1, Category E-C, Containment Surfaces Requiring Augmented Examination.
 
Included as one of the areas to evaluate for augmented inspections was the "Drywell SCV at the
 
sand bed region." The evaluation considered the potential degradation mechanisms of each
 
area; the adequacy of existing programs and maintenance practices with respect to the
 
monitoring, prevention, and correction of degradation; and industry experience applicable to the
 
area; and provided a conclusion with res pect to augmented examination requirements.
The applicant also stated that the drywell SCV at the sand bed region evaluation summarized the response to GL 87-05 and the need to obtain more data to conclude whether augmented
 
inspections were warranted. UT thickness measurements of this area, in accordance with 3-290 IWE-2500 (c)(2), (c)(3), and (c)(4), were obtained during the U3C8 and U2C10 refueling outages. The data indicate that the condition of the drywell steel liner plate in this area is good, and that this area should not be categorized for augmented examination for Units 2 and 3.
As part of the re-start activities for Unit 1, the applicant stated that a similar evaluation will be performed to determine if augmented inspections would be required. This evaluation and
 
conclusion will be included in BFN Technical Instruction 0-TI-376 prior to Unit 1 re-start.
In its response, the applicant also noted that aging management of drywell corrosion will be addressed in its response to RAI 3.5-4. This issue is dispositioned in the staff evaluation of the
 
applicant's response to RAI 3.5-4.
3.5.2.2.5  Loss of Prestress due to Relaxation, Shrinkage, Creep, and Elevated Temperature
 
The discussion in SRP-LR Section 3.5.2.2.1.5 is not applicable to BFN since BFN is a BWR with a Mark I steel containment.
3.5.2.2.6  Cumulative Fatigue Damage
 
In LRA Section 3.5.2.2.1.6, the applicant stated that fatigue analysis of BWR Mark I and Mark II containment steel elements, penetration sleeves, and penetration bellows are TLAAs as
 
defined in 10 CFR 54.3. The TLAA evaluation of cumulative fatigue damage is addressed in
 
LRA Section 4.6. The staff evaluated TLAAs in SER Section 4.
3.5.2.2.7  Cracking due to Cyclic Loading and Stress Corrosion Cracking
 
The staff reviewed LRA Section 3.5.2.2.1.7 against the criteria in SRP-LR Section 3.5.2.2.1.7.
 
In LRA Section 3.5.2.2.1.7, the applicant addressed aging mechanisms that can lead to cracking of penetration sleeves and penetration bellows such as cyclic loads and SCC.
SRP-LR Section 3.5.2.2.1.7 states that cracking of containment penetrations (including penetration sleeves, penetration bellows, and dissimilar metal welds) due to cyclic loading or
 
SCC could occur in all types of containments. Cracking could also occur in vent line bellows, vent headers and downcomers due to SCC for BWR containments. Further evaluation of
 
inspection methods is recommended to detect cracking due to cyclic loading and SCC since
 
visual VT-3 examinations may be unable to detect this aging effect.
Cracking Due to SCC. The GALL AMP XI.S1, "ASME Section XI Subsection IWE," covers inspection of these items under examination categories E-B, E-F, and E-P (10 CFR Part 50
 
Appendix J pressure tests). In 10 CFR 50.55a, examination categories E-B and E-F are
 
identified as optional during the current term of operation. For the extended period of operation, examination categories E-B and E-F, and additional appropriate examinations to detect SCC in
 
bellows assemblies and dissimilar metal welds, are warranted to address this issue.
In the LRA, the applicant stated that SCC of stainless steel exposed to atmospheric conditionsand contaminants is considered plausible only if the material temperature is above 140 °F. In general, SCC very rarely occurs in austenitic stainless steels below 140 °F. Although stress corrosion cracking has been observed in systems at temperatures lower than this 140 °F 3-291 threshold, all of these instances have identified a significant presence of contaminants (halogens, specifically chlorides) in the failed components. This material is at a relatively low
 
temperature, in a sheltered environment, and not exposed to a corrosive environment.
The applicant further stated in the LRA that industry experience, detailed in NRC information notice (IN) 92-20, described instances of the failure of the 10 CFR Part 50 Appendix J local leak
 
rate test (LLRT) to detect cracking in stainless steel containment penetration bellows. The LLRT
 
was inadequate due to the type of penetration bellows utilized at the nuclear power plant that is
 
the subject of the IN. The type of bellows used on the containment penetrations at BFN is not
 
the type described in IN 92-20. The vent line bellows are a single-ply bellows design. Pipe
 
penetration bellows for high-energy lines are two-ply bellows with a mesh. The design of the
 
penetration bellows allows full pressure to be transmitted to all portions of the bellows during
 
Appendix J testing. Containment penetrations bellows are not susceptible to failure of the
 
10 CFR Part 50 Appendix J LLRT to detect cracking, as described in IN 92-20. A review of the
 
operating history for the past five years did not indicate any failures associated with vent line
 
and penetration bellows. This issue was pursued in staff RAI 3.5-1 (see SER Section 3.5.2.3.1)
The applicant also stated in the LRA that the reinstatement of Examination Categories E-B and E-F would result in hardship or unusual difficulty for BFN without a compensating increase in
 
the level of quality and safety. Therefore, existing requirements for 10 CFR Part 50 Appendix J Program leak rate testing and visual examinations, in accordance with ASME Code Section XI, Subsection IWE, Examination Category E-A, should be adequate to detect cracking due to SCC. The reinstatement of ASME Code Section XI, Subsection IWE, Weld Examination
 
Categories E-B and E-F would not be required. Weld Examination Categories E-B and E-F have been removed from the ASME Code Section XI, 1998 Edition.
During the audit, the staff asked the applicant if there was any operating history at BFN beyond the past five years regarding signs of cracking and/or failures associated with the vent line and
 
penetration bellows. The staff also requested the applicant to discuss the hardship or unusual
 
difficulty for the applicant regarding reinstatement of Examination Categories E-B and E-F.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that during the last nine years there has been no operating experience to indicate that cracking
 
or other aging effects resulted in a loss of intended function of the vent line bellows or
 
penetration bellows.
The applicant further stated that, in accordance with 10 CFR 50.55a, the performance of examinations required by examination categor ies E-B and E-F are optional and that the staff found no evidence of industry problems with these welds. 
 
The applicant also stated that specific weld locations on the containment would be required to
 
be located and identified on weld maps in order to perform examinations for examination categories E-B and E-F. These weld locations have not been identified for the ASME Code Section XI Subsection IWE ISI Program. The hardship associated with performing the weld
 
examinations associated with examination categories E-B and E-F is attributed to radiation
 
exposure received while performing examinations of welds that have no industry experience of problems. Since specific weld locations have not been identified for the ASME Code Section XI Subsection IWE ISI Program, it is not possible to provide an estimated radiation
 
exposure for performance of the examinations.
3-292 The applicant's response also noted that the Summary of SECY-96-080, "Issuance Of Final
 
Amendment To 10 CFR 50.55a To Incorporate By Reference The ASME Boiler And Pressure Vessel Code (ASME Code), Section XI, Division 1, Subsection IWE And Subsection IWL,"
states the following:
The third modification, 50.55a(b)(2)(x)(C), makes the Subsection IWE pressure retaining welds and Subsection IWE pressure retaining dissimilar metal welds inspection
 
optional. The staff concluded that requiring these inspections is not appropriate. There
 
is no evidence of problems associated with welds of this type in operating plants.
 
Therefore, the occupational radiation exposure that would be incurred while performing
 
these inspections cannot be justified. It is estimated that the total occupational exposure
 
that would be incurred yearly in the performance of the containment weld inspections
 
would be 440 person-rems.
The staff found the applicant's response to be acceptable. 
 
Cracking Due to Cyclic Loading. Cracking of the containment shell and penetrations due to cyclic loading is a TLAA. The staff evaluated TLAAs in SER Section 4.
3.5.2.2.8  Aging of Structures Not Covered by Structures Monitoring Program
 
The staff reviewed LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1.
LRA Section 3.5.2.2.2.1 addresses aging of Class 1 structures not covered by the Structures
 
Monitoring Program.
SRP-LR Section 3.5.2.2.2.1 states that the GALL Report recommends further evaluation of certain structure/aging effect combinations if they are not covered by the Structures Monitoring
 
Program. This is described in GALL Report Chapter III and includes: (1) scaling, cracking, and
 
spalling due to repeated freeze-thaw for Groups 1-3, 5, 7-9 structures; (2) scaling, cracking, spalling and increases in porosity and permeability due to leaching of calcium hydroxide and
 
aggressive chemical attack for Groups 1-5, 7-9 structures; (3) expansion and cracking due to
 
reaction with aggregates for Groups 1-5, 7-9 structures; (4) cracking, spalling, loss of bond, and
 
loss of material due to corrosion of embedded steel for Groups 1-5, 7-9 structures; (5) cracks, distortion, and increase in component stress level due to settlement for Groups 1-3, 5, 7-9
 
structures; (6) reduction of foundation strength due to erosion of porous concrete
 
subfoundations for Groups 1-3, 5-9 structures; (7) loss of material due to corrosion of structural
 
steel components for Groups 1-5, 7-8 structures; (8) loss of strength and modulus of concrete
 
structures due to elevated temperatures for Groups 1-5; and (9) crack initiation and growth due
 
to SCC and loss of material due to crevice corrosion of stainless steel liner for Groups 7 and 8
 
structures. Further evaluation is necessary only for structure/aging effect combinations not
 
covered by the Structures Monitoring Program.
SRP-LR Section 3.5.2.2.2.1 references SRP-LR Subsection 3.5.2.2.1.2 for the technical details of the aging management issue for Items (5) and (6), above, and references SRP-LR
 
Section 3.5.2.2.1.3 for the technical details of the aging management issue for Item (8), above.
In LRA Section 3.5.2.2.2.1, the applicant stated that the further evaluations are also applied to Group 6 structures, when applicable; and that the technical details of the AMRs associated with 3-293 SRP-LR Section 3.5.2.2.1.2, "Cracking, Distortion, and Increase in Components Stress Level due to Settlement; Reduction of Foundation Strength due to Erosion of Porous Concrete
 
Subfoundations, if Not Covered by Structures Monitoring Program," and SRP-LR
 
Section 3.5.2.2.1.3, "Reduction of Strength and Modulus of Elasticity due to Elevated
 
Temperature," are also incorporated in this further evaluation.
The staff's evaluation for Items (1) through (9) is presented below:
  (1)Freeze-thaw The GALL Report, as updated by ISG-3, recommends that for accessible areas inspections performed in accordance with the Structures Monitoring Program will
 
indicate the presence of loss of material (spalling, scaling) and cracking due to
 
freeze-thaw. For inaccessible areas, evaluation is needed for plants that are located in
 
moderate to severe weathering conditions (weathering index >100 day-inch/yr)
(NUREG-1557). Documented evidence to confirm that the in-place concrete had the air
 
content of three to six percent and that subsequent inspections performed did not detect
 
degradation related to freeze-thaw should be considered a part of the evaluation. The
 
weathering index for the continental US is shown in ASTM C33-90, Figure 1.
In LRA Section 3.5.2.2.2.1, the applicant stated that BFN is located in an area with moderate weathering conditions, as noted on Figure 1 of ASTM C33-99. Freeze-thaw is
 
not considered an aging mechanism for concrete components below the frost line. The
 
concrete structures and concrete are designed in accordance with ACI 318-63 and ACI
 
318-71 and constructed using ingredients conforming to ACI and ASTM standards. TVA
 
specifications require all concrete to contain an air-entraining agent in sufficient quantity
 
to maintain specified percentages based on nominal maximum size aggregate. For
 
severe weather exposures (as defined in TVA-Specifications), the air content identified
 
varies from 4 to 10 percent, depending on aggregate size. Severe weather exposure (as
 
described in TVA-Specifications), is defined as "all exterior surfaces of concrete which
 
will be exposed to alternate wetting and drying."
The applicant further stated in the LRA that specified air content for reinforced concrete is greater than the three to six percent for air content identified in ISG-03. Therefore, loss
 
of material (spalling, scaling) and cracking due to freeze-thaw are aging effects that
 
require aging management in accordance with ISG-03 for below-grade (above the frost
 
line) reinforced concrete structures and components. Below-grade reinforced concrete
 
will be inspected by the Structures Monito ring Program when excavated for any reason.
Accessible exterior above-grade concrete will be monitored by the Structures Monitoring Program to manage loss of material and cracking due to freeze-thaw.
The staff concluded that the applicant's AMR for loss of material and cracking due to freeze-thaw is consistent with the GALL Report, and that the aging effects will be
 
adequately managed by the Structures Monitoring Program.
  (2)(a) Leaching of Calcium Hydroxide The GALL Report, as updated by ISG-3, recommends that for accessible areas inspections performed in accordance with the Structures Monitoring Program will
 
indicate the presence of increase in porosity and permeability due to leaching of calcium
 
hydroxide. For inaccessible areas, a plant-specific AMP is required for below-grade 3-294 inaccessible areas (basemat and concrete wall) if the concrete is exposed to flowing water (NUREG-1557). An AMP is not required, even if reinforced concrete is exposed to
 
flowing water, if there is documented evidence that confirms the in-place concrete was
 
constructed in accordance with the recommendations in ACI 201.2R-77.
In LRA Section 3.5.2.2.2.1, the applicant stated that concrete structures and concrete components are designed in accordance with ACI 318-63 and ACI 318-71 and
 
constructed using ingredients conforming to ACI and ASTM standards, which provide for
 
a good quality, dense, well cured, and low permeability concrete. Cracking is controlled
 
through proper arrangement and distribution of reinforcing steel. Concrete structures and
 
concrete components are constructed of a dense, well-cured concrete with an amount of
 
cement suitable for strength development, and achievement of a water-to-cement ratio which is characteristic of concrete having low permeability. This is consistent with the
 
recommendations and guidance provided by ACI 201.2R-77. In addition, concrete
 
components must be exposed to flowing water through the concrete component.
 
Leaching of calcium hydroxide is readily noticeable as white deposits that remain on the
 
concrete surface after a solution of water-free lime from the concrete and carbon dioxide
 
from the air is absorbed and dries. The Structures Monitoring Program inspects concrete
 
areas for signs of leaching. No significant signs of leaching have been documented
 
during these inspection walkdowns. Therefore, the conditions identified in the GALL
 
Report as revised by ISG-03 are satisfied, and aging management of an increase in
 
porosity and permeability and a loss of strength due to leaching of calcium hydroxide for
 
below-grade inaccessible concrete is not required. However, the Structures Monitoring
 
Program will be used to manage aging effects caused by an increase in porosity and
 
permeability and loss of strength due to leaching of calcium hydroxide of concrete.
The staff concluded that the applicant's AMR for scaling, cracking, spalling and increase in porosity and permeability due to leaching of calcium hydroxide is consistent with the
 
GALL Report, and that the aging effects will be adequately managed by the Structures
 
Monitoring Program.
  (2)(b) Aggressive Chemical Attack The GALL Report, as updated by ISG-3, recommends that for accessible areas, inspections performed in accordance with the Structures Monitoring Program will
 
indicate the presence of increase in porosity and permeability, cracking, or loss of
 
material (spalling, scaling) due to aggressive chemical attack. For inaccessible areas, a
 
plant-specific AMP is required (may be a part of Structures Monitoring Program) if the below-grade environment is aggressive (pH < 5.5; chlorides >500 ppm; or sulfates
 
>1500 ppm). Examination of representative samples of below-grade concrete, when
 
excavated for any reason, is to be included as part of a plant-specific program. The
 
GALL Report notes that periodic monitoring of below-grade water chemistry (including
 
consideration of potential seasonal variations) is an acceptable approach to demonstrate
 
that the below-grade environment is nonaggressive.
In LRA Section 3.5.2.2.2.1, the applicant stated that the Structures Monitoring Program will be used to inspect accessible concrete areas for aging effects caused by scaling, cracking, spalling and increase in porosity and permeability due to aggressive chemical
 
attack.
3-295 The staff concluded that the applicant's AMR for scaling, cracking, spalling and increase in porosity and permeability due to aggressive chemical attack is consistent with the
 
GALL Report for accessible areas, and that the aging effects will be adequately
 
managed by the Structures Monitoring Program. The staff's evaluation for inaccessible areas is in SER Section 3.5.2.2.9.  (3)Reaction with Aggregates The GALL Report, as updated by ISG-3, recommends that for accessible areas, inspections/evaluations performed in accordance with the Structures Monitoring
 
Program will indicate the presence of expansion and cracking due to reaction with
 
aggregates. For inaccessible areas, evaluation is needed if investigations, tests, and
 
petrographic examinations of aggregates performed in accordance with ASTM C295-54, ASTM C227-50, or ACI 201.2R-77 (NUREG-1557) demonstrate that the aggregates are
 
reactive.In LRA 3.5.2.2.2.1, the applicant stated that the aggregate used in the concrete of the BFN components did not come from a region known to yield aggregates suspected of, or
 
known to cause, aggregate reactions. Materials for concrete used in BFN structures and
 
components were specifically investigated, tested, and examined in accordance with
 
pertinent ASTM standards. All aggregates used at BFN conform to the requirements of ASTM C33 "Standard Specification of Concrete Aggregates." Appendix XI of ASTM C33
 
identifies methods for evaluating potential reactivity of aggregates including ASTM C295, ASTM C289, ASTM C227, and ASTM C342. If potentially reactive aggregates were used, then use of a low alkali Portland Cement (ASTM C150 Type II) containing less
 
than 0.60 percent alkali calculated as sodium oxide equivalent was required by
 
TVA-Specifications and will prevent harmful expansion due to alkali aggregate reaction.
 
Therefore, the conditions identified in the GALL Report as revised by ISG-03 are
 
satisfied, and aging management of expansion and cracking due to reaction with
 
aggregates for below-grade inaccessible concrete is not required. However, the
 
Structures Monitoring Program will be used to inspect accessible concrete areas for
 
aging effects caused by reaction with aggregates.
The staff concluded that the applicant's AMR for expansion and cracking due to reaction with aggregates is consistent with the GALL Report, and that the aging effects will be
 
adequately managed by the Structures Monitoring Program.
 
  (4)Corrosion of embedded steel The GALL Report, as updated by ISG-3, recommends that for accessible areas, inspections performed in accordance with the Structures Monitoring Program will
 
indicate the presence of cracking, loss of bond, and loss of material (spalling, scaling)
 
due to corrosion of embedded steel. For inaccessible areas, a plant-specific AMP is
 
required (may be a part of Structures Monitoring Program) if the below-grade
 
environment is aggressive (pH < 5.5, chlorides > 500ppm, or sulfates > 1500 ppm).
 
Examination of representative samples of below-grade concrete, when excavated for
 
any reason, is to be included as part of a plant-specific program. The GALL Report notes
 
that periodic monitoring of below-grade water chemistry (including consideration of
 
potential seasonal variations) is an acceptable approach to demonstrate that the
 
below-grade environment is aggressive or nonaggressive.
3-296 In LRA 3.5.2.2.2.1, the applicant stated that BFN will use the Structures Monitoring Program to inspect accessible concrete areas for aging effects caused by corrosion of
 
embedded steel.
The staff concluded that the applicant's AMR for cracking, spalling, loss of bond, and loss of material due to corrosion of embedded steel is consistent with the GALL Report
 
for accessible areas, and that the aging effects will be adequately managed by the
 
Structures Monitoring Program. The staff's evaluation for inaccessible areas is in SER
 
Section 3.5.2.2.9.  (5)Settlement SRP-LR Section 3.5.2.2.2.1 refers to SRP-LR Section 3.5.2.2.1.2 for discussion of settlement. SRP-LR Section 3.5.2.2.1.2 states that cracking, distortion, and increase in
 
component stress level due to settlement could occur in Class 1 structures. Some plants
 
may rely on a de-watering system to lower the site ground water level. If the plant's CLB
 
credits a de-watering system, the GALL Report recommends verification of the
 
continued functionality of the de-watering system during the period of extended
 
operation. The GALL Report recommends no further evaluation if this activity is included
 
in the scope of the applicant's Structures Monitoring Program.
In LRA Section 3.5.2.2.2.1, the applicant stated that cracks, distortion, and increase in component stress level due to settlement are not considered AERM for structures
 
founded on rock or bearing piles. The following BFN structures are founded on rock or
 
bearing piles: reactor buildings, primary containments, intake pumping station, reinforced
 
concrete chimney, off-gas treatment building, equipment access lock, turbine buildings, gate structure number 3, diesel HPFP house, transformer yard, and RHRSW tunnel.
 
Based on industry experience, settlement of Class 1 structures founded on bedrock or
 
bearing piles have not been noted to cause AERM.
For concrete structures founded on dense soil or backfill, the applicant stated that it can be concluded that cracking due to settlement is not significant if in the past 20 years of
 
operating experience for a structure the total differential settlement experienced is well
 
within the permissible limits for this type of structure and no settlement has manifested
 
itself via cracked walls or cracked foundations. In this case, aging management for
 
settlement would not be applicable for the structure during the period of extended
 
operation. Prior settlement monitoring progr ams have revealed that soil settlement has stabilized and the structures will continue to perform their intended functions. However, due to prior operating history of settlement in the 1980s at BFN, cracking and distortion
 
due to settlement of structures founded on soil or backfill will be monitored by the
 
Structures Monitoring Program.
The staff concluded that the applicant's AMR for cracks, distortion, and increase in component stress level due to settlement is consistent with the GALL Report, and that
 
the aging effects will be adequately managed by the Structures Monitoring Program.  (6)Erosion of porous concrete subfoundation The GALL Report states that erosion of cement from porous concrete subfoundations beneath containment basemats is described in IN 97-11. IN 98-26 proposes
 
Maintenance Rule structures monitoring for managing this aging effect, if applicable. If a
 
dewatering system is relied upon for control of erosion of cement from porous concrete 3-297 subfoundations, then the applicant is to ensure proper functioning of the dewatering system through the period of extended operation.
In LRA 3.5.2.2.2.1, the applicant stated that the evaluation of Information Notice 98-26 concluded that porous concrete subfoundations were not used at BFN. A dewatering
 
system is not relied upon for control of erosion of cement from porous concrete
 
subfoundations. Therefore, reduction in foundation strength, cracking, and differential
 
settlement due to erosion of porous concrete subfoundation are not applicable.
The staff concluded that the applicant's AMR for reduction in foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundation is
 
consistent with the GALL Report, and that these aging effects are not applicable.  (7)Corrosion of structural steel components The GALL Report states that further evaluation is necessary only for structure/aging effect combinations not covered by the Structures Monitoring Program. If protective
 
coatings are relied upon to manage the effects of aging, the Structures Monitoring
 
Program is to include requirements to address monitoring and maintenance of protective
 
coatings.In LRA Section 3.5.2.2.2.1, the applicant stated that the Structures Monitoring Program will manage loss of material due to corrosion of structural steel components. The
 
Structures Monitoring Program procedures specify visual inspections of structural
 
conditions as the method used to detect degradation.
The applicant further stated that, for the steel that is embedded/encased within the concrete, corrosion is not an applicable aging mechanism. The concrete must first be
 
degraded by other aging mechanisms, which reduce the protective cover and allow for
 
the intrusion of aggressive ions causing a reduction in concrete pH. Aging management
 
of previously noted concrete aging effects will manage loss of material for steel that is
 
embedded/encased within concrete.
The applicant also makes note that NUREG-1557, Table B9, states that steel piles driven in undisturbed soil have been unaffected by corrosion and those driven in
 
disturbed soil experience minor to moderate corrosion to a small area of metal. Loss of
 
material for steel piles driven in undisturbed or disturbed soil does not require aging
 
management.
The applicant also stated that the protective coating monitoring and maintenance program is not credited for aging management of loss of material for structural steel
 
components.
The staff concluded that the applicant's AMR for loss of material due to corrosion of structural steel components is consistent with the GALL Report, and that the aging
 
effects will be adequately managed by the Structures Monitoring Program. The staff also
 
concurred with the applicant's AMR for steel piles, because it is based on a documented staff technical assessment.  (8)Elevated temperatures 3-298 The GALL Report calls for a plant-specific AMP and recommends further evaluation if any portion of the concrete components exc eeds specified temperature limits, (i.e.,general area temperature 66 &deg;C (150 &deg;F) and local area temperature 93 &deg;C (200 &deg;F)).
In LRA Section 3.5.2.2.2.1, the applicant stated that with the exception of the main steam tunnels in the reactor building BFN reinforced concrete structures have general area temperatures less than 150 &deg;F during normal operation. General area temperatures
 
have been conservatively evaluated using maximum normal space ambient
 
temperatures noted on the harsh environmental drawing series and associated
 
calculations. The main steam tunnels have a maximum normal space ambient temperature of 160 &deg;F, as noted in the harsh environmental drawing series and
 
associated calculations. This is a maximum normal space ambient temperature. The
 
harsh environmental drawing series and associated calculations identify the space average normal ambient temperature as 135 &deg;F. This is judged to be acceptable by the
 
applicant, because when concrete is subjected to prolonged exposure to elevated
 
temperatures reductions in excess of 10 percent of the compressive strength, tensile strength, and the modulus of elasticity begin to occur in the range of 180 &deg;F to 200 &deg;F.
The applicant further stated that each drywell is cooled during normal plant operation by a closed-loop ventilation system designed to keep the average temperature in thedrywell less than 150 &deg;F. The general area temperature inside the drywell (primary containment) is maintained below 150 &deg;F as required by Technical Specifications.
 
Elevated temperatures on internal concrete components such as the reactor support pedestal, where the temperature could approach 150 &deg;F, are addressed as appropriate
 
by BFN civil design criteria. The drywell concrete structure surrounding the drywell
 
vessel was evaluated for thermal effects from the general area temperature of the drywell. The upper elevations of the sacrificial shield wall may exceed 150 &deg;F briefly and
 
infrequently, during abnormal operations; this is not considered to affect its function.
The applicant concluded that the conditions identified in the GALL Report are satisfied and aging management for reduction of strength and modulus due to elevated
 
temperature for concrete components is not required.
During the audit, the staff requested the applicant to:
  (1)Explain how the elevated temperature on internal concrete components, wherethe temperature could approach 150 &deg;F, are addressed by BFN civil design
 
criteria.  (2)Discuss the evaluation of the drywell concrete structure for thermal effects.
  (3)Discuss the technical basis for concluding that "the upper elevations of thesacrificial shield wall may exceed 150 &deg;F briefly and infrequently, during abnormal
 
operations and is not considered to affect its functions."    (4)Discuss the local temperatures that can be expected in the concrete surrounding hot piping penetrations and what provisions exist for maintaining these
 
temperatures within acceptable limits.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the GDC document, BFN-50-C-7100 "Design of Civil Structures" (DC),
provides the design basis requirements for all BFN structures, including the primary
 
containment. In DC Section 3.2.5, Appendix C, the temperature requirements are 3-299defined for the drywell concrete, with an operating temperature of 150 &deg;F specified for the drywell.
DC Appendix C, Table 15-10, "Reactor Support Pedestal Design Data," provides the principal design cases for the reactor support pedestal and includes the requirement to
 
consider thermal effects for each principal design case. DC Appendix C, Table 15-12, "Reactor Building Concrete Structure Fuel Pool Storage Pool and Dryer/Separator
 
Storage Pool Design Data," requires the consideration of drywell thermal rise for the
 
appropriate principal design cases for the spent fuel storage pool and dryer/separator
 
storage pool of the reactor building. Both these pools have structural elements that form
 
portions of the outer structural concrete shell of the primary containment steel shell. DC
 
Appendix C, Table 15-15(a), "Drywell Concrete Structure," provides the principal design
 
cases for the drywell concrete and requires the consideration of thermal effects in the
 
principal loading combinations for the drywell concrete structure.
The applicant further stated that the sacrificial shield wall provides a biological shield for protection of personnel from gamma radiation, a neutron shield to prevent activation of
 
the drywell components during operation, and a means of supporting the drywell pipe
 
hangers and access platform. It also provides protection against damage to the nuclear
 
system process barrier due to seismic loading, against further damage due to vessel
 
pipe penetration rupture jet forces, and a limit stop and support for pipe restraints in the
 
event of a drywell pipe rupture. It consists of a 24-foot diameter circular cylinder attached to the vessel support pedestal and extending upward approximately 45 feet. The
 
sacrificial shield wall is 27 inches thick and is constructed from 26-inch vertical WF beam
 
columns, tied together by horizontal WF beams and 1/4-inch plates.
The applicant stated that the 1/4-inch plates are welded to the column flanges, both inside and outside, thereby forming a double-walled shell. This shell is filled with concrete to
 
provide biological shielding capability. The concrete was assumed to have no structural
 
purpose, except for the lowest 10 feet 6 inches of the wall. Based on the design criterion
 
that the concrete has no structural purpose except for the lowest 10.5 feet, the applicant concluded that "the upper elevations of the sacrificial shield wall may exceed the 150 &deg;F
 
briefly and infrequently during abnormal operation and is not considered to affect its
 
function," as stated in LRA 3.5.2.2.2.1, Item 8.
In its response, the applicant also noted that degradation of drywell concrete due to elevated temperature would be addressed in its response to RAI 3.5-5. This issue will be
 
dispositioned in the staff evaluation of the applicant's response to RAI 3.5-5.    (9)Aging Effects for Stainless Steel Liners for Tanks In LRA Section 3.5.2.2.2.1, the applicant stated that BFN does not have any Group 7 structures or in-scope stainless steel liners in an exposed-to-fluid environment for any
 
Group 8 structures. The staff concluded that further evaluation of this aging effect is not
 
applicable.
In summary, the staff found that the applicant had demonstrated that the effects of aging, with the exception of elevated temperatures, will be adequately managed by the Structures Monitoring Program, so that the intended functions will be maintained
 
consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
3-300 3.5.2.2.9  Aging Management of Inaccessible Areas The staff reviewed LRA Section 3.5.2.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2.2. In LRA Section 3.5.2.2.2.2, the applicant addressed aging of inaccessible areas of Class 1
 
structures.
SRP-LR Section 3.5.2.2.2.2 states that cracking, spalling, and increases in porosity and permeability due to aggressive chemical attack; and cracking, spalling, loss of bond, and loss of
 
material due to corrosion of embedded steel could occur in below-grade inaccessible concrete
 
areas. The GALL Report recommends further evaluation to manage these aging effects in
 
inaccessible areas of Groups 1-3, 5, 7-9 structures, if an aggressive below-grade environment
 
exists. ISG-3 identifies additional requirements.
The GALL Report, as updated by ISG-3, states that for inaccessible areas, a plant-specific AMP is required (may be part of Structures Moni toring Program) if the below-grade environment is aggressive (pH < 5.5; chlorides > 500 ppm; or sulfates > 1500 ppm). Examination of
 
representative samples of below-grade concrete, when excavated for any reason, is to be
 
included as part of a plant-specific program. The GALL Report also notes that periodic
 
monitoring of below-grade water chemistry (including consideration of potential seasonal
 
variations) is an acceptable approach to demonstrate that the below-grade environment is
 
nonaggressive.
In LRA Section 3.5.2.2.2.2, the applicant stated that design and construction of reinforced concrete provides dense, well cured, and low permeability concrete with an acceptable degree
 
of protection for the embedded steel against exposure to an aggressive environment. Cracking
 
of concrete is controlled through proper arrangement and distribution of reinforcing steel.
The applicant further stated that continued or frequent cyclic exposure to the following aggressive environments is necessary for aggressive chemicals to cause significant aggressive
 
chemical attack or corrosion of embedded steel:
* acidic solutions with pH less than 5.5
* chloride solutions greater than 500 ppm
* sulfate solutions greater than 1500 ppm The applicant stated that aggressive chemicals are present at plant sites, system leakage is leakage that could cause aggressive chemical attack is possible. However, leaks are not
 
expected to continue for the extensive periods required for degradation, and repairs would be
 
completed prior to loss of intended function. An aggressive environment may also occur where
 
concrete is exposed to aggressive aqueous solutions such as groundwater or aggressive water
 
flow. Groundwater sample measurements confirm that parameters are below threshold limits that could cause aggressive chemical attack for below-grade inaccessible concrete. Natural
 
groundwater movement in this area is from the plant site to Wheeler Reservoir. Wheeler
 
Reservoir water samples also confirm that an aggressive environment does not exist. Therefore, the applicant concludes that the conditions identified in the GALL Report, as revised by ISG-03, are satisfied and aging management of cracking, spalling, and increases in porosity and
 
permeability due to aggressive chemical attack; and cracking, spalling, loss of bond and loss of
 
material due to corrosion of embedded steel is not required for below-grade inaccessible
 
concrete.
3-301 The applicant concluded that Browns Ferry groundwater and Wheeler Reservoir sample measurements have confirmed that parameters are well below threshold limits that could cause concrete degradation (an aggressive environment does not exist) and that the rate of
 
groundwater flow is not considered aggressive.
The applicant stated that BFN does not commit to periodic groundwater monitoring over the period of license extension, since it is not credible to postulate that some environmental event
 
will occur in the future that would affect the quality of groundwater in the vicinity of Browns
 
Ferry. A change in the environment due to a chemical release would be considered an
 
abnormal event.
SRP-LR states that aging effects from abnormal events need not be postulated specifically for license renewal.
The staff found that the applicant's response is not consistent with the GALL Report recommendation for periodic monitoring of groundwater. This issue was dispositioned by the
 
staff, based on the applicant's responses to RAIs 3.5-7 and 3.5-8 and is discussed in SER
 
Section 3.5.2.3.2.
3.5.2.2.10  Aging of Supports Not Covered by Structures Monitoring Program
 
The staff reviewed LRA Section 3.5.2.2.3.1 against the criteria in SRP-LR Section 3.5.2.2.3.1. In LRA Section 3.5.2.2.3.1, the applicant addressed aging of component supports that are not
 
managed by the Structures Monitoring Program.
SRP-LR Section 3.5.2.2.3.1 states that the GALL Report recommends further evaluation of certain component support/aging effect combinations if they are not covered by the Structures
 
Monitoring Program. This includes (1) reduction in concrete anchor capacity due to degradation
 
of the surrounding concrete for Groups B1-B5 supports; (2) loss of material due to
 
environmental corrosion for Groups B2-B5 supports; and (3) reduction/loss of isolation function
 
due to degradation of vibration isolation elements for Group B4 supports. Further evaluation is
 
necessary only for structure/aging effect combinations not covered by the Structures Monitoring
 
Program.    (1)Reduction in concrete anchor capacity due to degradation of the surrounding concrete for Groups B1 through B5 supports.
In LRA Section 3.5.2.2.3.1, the applicant stated that reduction in concrete anchor capacity due to local concrete degradation for Groups B1 - B5 supports will be managed
 
by the Structures Monitoring Program.  (2)Loss of material due to environmental corrosion, for Groups B2-B5 supports.
In LRA Section 3.5.2.2.3.1, the applicant stated that loss of material due to environmental corrosion for Groups B2 - B5 Supports will be managed by the Structures
 
Monitoring Program.  (3)Reduction/loss of isolation function due to degradation of vibration isolation elements for Group B4 supports.
In LRA Section 3.5.2.2.3.1, the applicant stated that there are no vibration elements within the scope of license renewal.
3-302 The staff found that the applicant had appropriately evaluated AMR results involving management of aging of component supports, as recommended in the GALL Report. The staff
 
found that the applicant had demonstrated that the effects of aging will be adequately managed
 
so that the intended functions will be maintained consistent with the CLB for the period of
 
extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.2.11  Cumulative Fatigue Damage due to Cyclic Loading
 
Cumulative fatigue damage is a TLAA. TLAAs are evaluated in SER Section 4.
 
3.5.2.2.12  Quality Assurance for Aging Management of Non-Safety-Related Components SER Section 3.0.4 provides a separate evaluation of the applicant's Quality Assurance Program.Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report
 
recommends further evaluation, the staff determined that (1) those attributes or features for
 
which the applicant claimed consistency with the GALL Report were indeed consistent, and (2)
 
the applicant had adequately addressed the issues that were further evaluated. The staff found
 
that the applicant had demonstrated that the effects of aging will be adequately managed so
 
that the intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).3.5.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.5.2.1 through 3.5.2.26, the staff reviewed additional details of the results of the AMRs for MEAP combinations that are
 
not consistent with the GALL Report, or that are not addressed in the GALL Report.
In LRA Tables 3.5.2.1 through 3.5.2.26, the applicant indicated, via Notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a
 
line item in the GALL Report, and provided inform ation concerning how the aging effect will be managed. Specifically, Note F indicated that the material for the AMR line item component is not
 
evaluated in the GALL Report. Note G indicated that the environment for the AMR line item
 
component and material is not evaluated in the GALL Report. Note H indicated that the aging
 
effect for the AMR line item component, materi al, and environment combination is not evaluated in the GALL Report. Note I indicated that the aging effect identified in the GALL Report for the
 
line item component, material, and environment combination is not applicable. Note J indicated
 
that neither the component nor the material and environment combination for the line item is
 
evaluated in the GALL Report.
Staff Evaluation. During the onsite audit, the staff reviewed selected items in all applicable LRA Table 3.5 items for MEAP combinations that are not consistent with the GALL Report. The staff
 
requested clarifications for the following material/environment combinations and the
 
corresponding LRA Table 2 items:
Carbon Steel in an Embedded/Encased Environment - It is recognized that all metals embedded/encased in concrete are inaccessible; however, they could be susceptible to aging 3-303 degradation. The staff requested that the applicant provide an AMR for further evaluation of embedded/encased components if aging of components in accessible areas is identified that
 
may indicate aging of the inaccessible components.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the BFN concrete structures and concrete components are designed in accordance with
 
ACI 318-63 and 71 and constructed using ingredients conforming to ACI and ASTM Code
 
standards, which provide for a good quality, dense, well cured, and low permeability concrete.
 
Cracking is controlled through proper arrangement and distribution of reinforcing bars.
The applicant further stated that concrete structures and concrete components are constructed of a dense, well-cured concrete with an amount of cement suitable for strength development, and achievement of a water-to-cement ratio that is characteristic of concrete having low 
 
permeability. This is consistent with the recommendations and guidance provided by
 
ACI 201.2R-77.
The applicant also stated that, as a minimum, all exposed portions of embedded/encased carbon steel structural components are inspected by the Structures Monitoring Program for the following aging effects:
* outside air environments: loss of material due to general and pitting corrosion
* inside air environments: loss of material due to general corrosion
* containment air environments: loss of material due to general corrosion The applicant concluded that the condition of the exposed portion of the embedded/encased carbon steel will provide an indication of the condition of the embedded/encased portion of the
 
carbon steel. If a deficient condition were identified for the exposed portion of the
 
embedded/encased carbon steel material, the Corrective Action Program (SPP-3.1) would
 
document the deficient condition. Resolution of the deficient condition would require the
 
development of a corrective action plan and consider ation would be given to the extent of the deficient condition in the development of the corrective actions, which would include the
 
embedded/encased portion of the material as warranted by the deficient condition.
The applicant also stated that a review of BFN operating history did not reveal any loss of intended function due to aging effects for carbon steel components embedded/encased in
 
concrete.
The staff found that the applicant had identified an appropriate course of action, through its Corrective Action Program, to manage aging of carbon steel components embedded/encased in
 
concrete, if a deficient condition is identified for the exposed portion of the embedded/encased
 
carbon steel material. On this basis, the staff accepts the applicant's AMR results for carbon
 
steel in an embedded/encased environment.
Stainless Steel in Containment Air, Inside Air and Outside Air Environments - The staff requested that the applicant provide the technical basis for concluding that the BFN stainless
 
steel components do not require aging management for any aging effects/mechanisms in
 
containment atmosphere, inside air, and outside air environments.
3-304 By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the AMR evaluation for stainless steel in a containment atmosphere, inside air, and outside
 
air is not susceptible to loss of material in for these environments. Stainless steels form a
 
passive film that prevents corrosion. Only a corrosive wetted environment is conducive to promoting aging degradation of stainless steel. Alternate wetting and drying in an outside air
 
environment has shown a tendency to 'wash' the exterior surfaces, cleaning the surface rather
 
than concentrating any corrosive contaminants (ref EPRI 1003056 Mechanical Tools). SCC of
 
stainless steel, which is only considered plausible in wetted corrosive environments greater than 140 &deg;F, will not occur in the containment at mosphere environment, inside air environment, or outside air environment.
The staff found the applicant's AMR results to be acceptable for stainless steel structural components and stainless steel non-ASME supports. In the absence of corrosive contaminants and temperatures greater than 140 &deg;F, stainless steel material is not susceptible to loss of
 
material due to corrosion and cracking due to SCC. Therefore, aging management for loss of
 
material and cracking in the containment at mosphere environment, an inside air environment, or an outside air environment is not required.
In its response, the applicant also stated that ASME stainless steel equivalent supports aresubject to the requirements of ASME Code Section XI, Subsection IWF during the period of
 
extended operation. However, the staff determined that the applicant had not credited IWF for
 
aging management of ASME stainless steel equivalent supports during the extended period of
 
operation, because the applicant's AMR had not identified any applicable aging effects. The
 
staff requested additional information to resolve this issue and related issues. The disposition is
 
discussed in SER 3.5.2.3.26, as part of the review of LRA Table 3.5.2.26 AMRs.
For component type, material, and environment combinations that are not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant
 
had demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation.
 
The staff's evaluation is discussed in the following sections.
3.5.2.3.1  Primary Containment Structures
- Summary of Aging Management Evaluation -
Table 3.5.2.1 The staff reviewed LRA Table 3.5.2.1, which summarizes the results of AMR evaluations for the primary containment structures component groups.
During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.1, for MEAP combinations that are not consistent with the GALL Report. The staff requested clarifications for
 
the following material/environment combinations and the corresponding LRA Table 2 items:
Lubrite in a Containment Air Environment
- The staff requested that the applicant describe where the referenced items are used and provide the technical basis for concluding that no
 
aging management of the lubrite plates used in BFN is required in a containment atmosphere.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that Table 3.5.2.1, row 37 applies to the lubrite plates used for the drywell floor beam seats.
 
EPRI 1002950, "Aging Effects for Structures and Structural Components (Structural Tools),
3-305 Revision 1," states that lubrite material resists deformation, has a low coefficient of friction, resists softening at elevated temperatures, absorbs grit and abrasive particles, is not
 
susceptible to corrosion, withstands high intensities of radiation, and will not score or mar.
 
Lubrite products are solid, permanent, completely self lubricating, and require no maintenance.
 
The containment atmosphere at the location of the drywell floor beam seats is not an aggressive
 
or wetted environment.
The applicant also stated that a search of BFN and industry operating experience did not identify any instances of lubrite plate degradation or failure to perform its intended function due
 
to aging effects. NUREG-1759, "Safety Evaluation Report Related to the License Renewal of
 
Turkey Point Nuclear Plant, Units 3 and 4" and NUREG-1769, "Safety Evaluation Report
 
Related to the License Renewal of Peach Bottom Atomic Power Station, Units 2 and 3," concur
 
that there are no lubrite plate aging effects that require aging management.
Based on the additional information provided by the applicant, the staff finds the applicant's AMR results for lubrite plates to be acceptable. Prior staff evaluations of this issue have
 
concluded that there are no aging effects requiring aging management.
The staff's review of LRA Table 3.5.2.1 identified areas in which additional information was necessary to complete the review of the applicant's program elements. The applicant responded
 
to the staff's RAI as discussed below.
In RAI 3.5-1, dated December 10, 2004, the staff inquired about the leakage rate testing of containment penetration bellows by pointing out that LRA Table 3.5.1, Item Numbers 3.5.1.3
 
and 3.5.1.17, indicate that the AMR results are consistent with the GALL Report, with the exceptions described in ASME Code Section XI Subsection IWE Program. The GALL Report, Item B.1.1.1-d recommends further evaluation regarding the SCC of containment bellows. In the
 
discussion of these items in LRA Section 3.5.2.2.1.7, the applicant asserted that Appendix J, Type B testing was effective in detecting leakages through the vent line bellows, as well as
 
through other pressure boundary bellows. The staff requested the applicant to provide
 
additional information regarding the frequency of Type B testing (performance-based intervals, in accordance with Option B, Appendix J) of containment pressure boundary bellows at Units 2
 
and 3, and the status of these bellows for Unit 1.
In its response, by letter dated January 31, 2005, the applicant quoted the content of LRA Section 3.5.2.2.1.7 and then stated:
BFN pipe penetration bellows are 10 CFR 50, Appendix J, Type B tested. BFN vent line bellows are 10 CFR 50, Appendix J, Type A tested.
Type B and C tests are performed prior to initial reactor operation. Subsequent Type B and C tests are performed at a frequency of at least once per 30 months until
 
performance data are collected for evaluation for extended test interval in accordance
 
with RG 1.163. Type B tests may use an extended interval of up to 120 months (excluding airlocks). Unit 2 and 3 bellows are tested at a 60-month test interval. There
 
have been no bellows failures on either Unit 2 or 3 bellows. Prior to the restart of Unit 1, Appendix J, Type B testing of containment pipe penetration bellows will be performed.
 
Unit 1 bellows will be tested at least once per 30 months until test performance data is
 
available to justify an extended test interval under Option B.
3-306 The staff noted that the vent line bellows are single-ply, and their leakage rates and aging degradation are managed by Appendix J, Type A testing. As Appendix J, Type A testing is
 
generally performed at 10-year intervals or great er, it was not clear to the staff how the leaktightness and structural integrity of the vent line bellows were maintained. The applicant
 
was requested to provide the frequency at which the Type A testing is performed in each unit, and the process by which the integrity of the vent line bellows is maintained, including
 
corresponding operating experience.
In its letter dated May 31, 2005, the applicant stated that it has been granted a one-time 5-year extension by the staff for performing the Type A test, and emphasized that there had been no
 
performance-based Type A test failure on Units 2 or 3. The applicant plans to perform an
 
Appendix J, Type A integrated leak rate test (ILRT) on Unit 1 prior to restart. The Unit 1
 
Appendix J, Type A test will be performed at leas t once every 48 months until test performance data are available to justify an extended test interval under Option B. Moreover, the applicant
 
provided a detailed description of the history of the visual examinations performed under its
 
plant procedures 2-TI-173 and 3-TI-173 which performs a general visual examination each
 
inspection period (three periods per 10 year interval). Different from other BWR Mark I
 
containments, the single-ply vent line bellows at the three BFN units are accessible for
 
examination from the torus interior. A VT-3, visual examination is performed each inspection interval in accordance with plant procedure 0-TI-376. The applicant emphasized that these
 
examinations are thorough as they are perfo rmed by NDE-certified personnel with specific lighting and visual acuity requirements. Additionally, plant procedure 0-SI-4.7.A.2.K, "Primary
 
Containment Drywell Surface Visual Exam ination," is performed each operating cycle.
Based on the detailed response regarding the detection of flaws in vent line bellows provided by the applicant, the staff found the applicant's process for ensuring the integrity of the vent line
 
bellows acceptable. Therefore, the staff's concern described in RAI 3.5-1 is resolved.
In RAI 3.5-2, dated December 10, 2004, the staff stated that, for seals and gaskets related to containment penetration, LRA Table 3.5.1, Item Number 3.5.1.6 and component type, "Compressible Joints and Seals," in LRA Table 3.5.2.1, the ASME Code Section XI Subsection
 
IWE Program and the 10 CFR 50 Appendix J Program have been identified as AMPs. Based on Exception 1 in the ASME Code Section XI Subsection IWE Program, the AMP will not be
 
applicable for aging management of containment seals and gaskets. For equipment hatches
 
and air-locks, the assumption is that the leak rate testing program will monitor aging degradation of seals and gaskets, as they are leak rate tested after each opening. Therefore, the staff requested that the applicant clarify whether these assumptions are correct. For other penetrations (mechanical and electrical) with seals and gaskets, the applicant was requested to
 
provide information regarding the adequacy of Type B leak rate testing frequency to monitor
 
aging degradation of seals and gaskets of containment drywells. The applicant was also
 
requested to provide the status of seals and gaskets of these penetrations at Unit 1.
In its response, by letter dated January 31, 2005, the applicant stated:ASME Section XI, 1992 Edition, 1992 Addenda, Category E-D, Item Numbers E5.10 (Seals), and E5.20 (Gaskets) requires a visual examination, VT-3, of containment seals
 
and gaskets. Examination of most seals and gaskets requires the joints to be
 
disassembled. When the airlocks, hatches, electrical penetrations, and flanged
 
connections are tested in accordance with 10 CFR 50, Appendix J, degradation of the 3-307 seal or gasket material would be revealed by an increase in the leakage rate. Corrective measures would be applied and the component retested.
For Units 1, 2, and 3, Relief Request CISI-1 was granted to perform Appendix J test in lieu of the visual examination, VT-3, on the containment seals and gaskets. The
 
moisture barriers continue to receive a visual VT-3 examination in accordance with
 
Category E-D for Units 1, 2, and 3. The scope of the 10 CFR 50 Appendix J Program
 
includes all pressure-retaining components, the containment shell (drywell and torus)
 
and penetrations. The following components are included in the scope of the program:
* containment penetration seals on airlocks, hatches, spare penetrations with flange connections, electrical penetrations and other devices required to assure
 
containment leak-tight integrity;
* containment penetration gaskets on airlocks, spare penetrations with flange connections, and other devices required to assure containment leak-tight
 
integrity;
* pressure retaining bolted connections;
* containment penetration bellows; and
* airlocks.
Units 2 and 3 O-ring seals (flanges, hatches, etc.) are tested on either a 30 or 60-month interval. Seal failures have occurred sporadically since restart. The Unit 2 and Unit 3
 
drywell heads have experienced failures and are currently classified as Maintenance
 
Rule (a)(1) for corrective actions. There are currently no electrical penetration
 
performance problems on Unit 2. All electrical penetrations on Unit 2 are currently on a
 
120-month test interval. Testing has identified only minor problems such as gauge, tubing, and root valve leaks. Unit 3 electrical penetrations are on 30, 60, or 72-month
 
test intervals. In general, testing has identified only minor problems such as gauge, tubing, and root valve leaks. However, one electrical penetration (3-EPEN-100-0101C)
 
on Unit 3 experienced a failure, was repaired, and is being tested on a 30-month test
 
interval. Other electrical penetrations are being tested at a 60-month interval. The
 
remainder of the Unit 3 electrical penetrations are on a 72-month interval.
Type B testing will be performed as part of the Unit 1 restart effort and will continue at least once per 30 months until test performance data is available to justify an extended
 
test interval under Option B.
The applicant described the existing process used in identifying degradation of the primary containment penetration seals and gaskets and plans to continue with the testing and corrective
 
action process during the period of extended operation. Therefore, the staff found the
 
applicant's process for managing the aging of the pressure-retaining seals and gaskets of
 
primary containments acceptable. The staff's concerns described in RAI 3.5-2 are resolved.
In RAI 3.5-3, dated December 10, 2004, the staff stated that the containment drywell-head to drywell joint consists of a pressure unseating containment boundary with pre-loaded bolts.
 
Loosened bolts and deteriorated gasket and/or seals can breach containment pressure boundary. Exceptions 1 and 2 taken in the ASME Section XI Subsection IWE Program will 3-308 preclude examinations of seals and bolts of this joint. Only Type A leak rate testing and associated visual examination requirements of the 10 CFR 50 Appendix J Program can be
 
relied upon to detect defects and degradation of this joint. The test interval for Type A leak rate
 
testing can be 10 to 15 years. Therefore, the staff requested the applicant to provide (1)
 
information regarding the plans and programs that are used to ensure the integrity of this joint
 
for each containment and (2) the status of the components (O-rings and bolts) at this joint for
 
Unit 1.In its response, by letter dated January 31, 2005, the applicant stated:
These containment pressure boundary components will continue to be inspected consistent with the Browns Ferry CLB for 10 CFR Part 50, Appendix J requirements. On
 
Units 2 and Unit 3 the Type A test frequency is currently on a 10-year interval. There
 
have been no performance based Type A test failures on Unit 2 or Unit 3. A Type A
 
Integrated Leak Rate Test will be performed as part of the Unit 1 restart effort. Type B
 
testing is also performed on the drywell-head seal every refueling outage for all three
 
units. Therefore, in combination of the Type A tests and Type B tests, integrity for this
 
joint for each containment is assured. Exception 2 pertains to bolt torque or tension
 
testing. Pressure retaining bolting associated with the Containment drywell-head to drywell joint is examined in accordance with ASME Section XI Subsection IWE.
The applicant performs Type B testing of the dr ywell-head seal every outage, and examines the pressure retaining bolts of the drywell head in accordance with Subsection IWE of the ASME Section XI Code. The staff accepts that these two activities together with periodic Type A testing
 
will ensure the integrity of this joint. Therefore, the staff found the applicant's practice of
 
ensuring the integrity of this joint acceptable. The staff's concern described in RAI 3.5-3 is
 
resolved.In RAI 3.5-4, dated December 10, 2004, the staff stated that the water leakages from the sand drains have been found in Units 2 and 3, and the results of the UT examinations performed from
 
the accessible areas of the drywells have indicated that the condition of the drywell shells was
 
good, and these areas did not require augmented examination. Therefore, the staff requested
 
that the applicant provide the following additional information related to the drywell shell
 
corrosion in this area for each containment drywell:  a.In other Mark I containments, the cause of water leakage from the sand-bed drains has been found to be water leaking from the refueling cavity (see IN 86-99, "Degradation of
 
Steel Containments)." As no water leakage has been indicated from Unit 1 (having no
 
refueling activities during its long layup), it would appear that the cause of the water
 
leakage in Units 2 and 3 could be the same as that described in the information notice.
 
Provide a discussion of the root cause in this context. b.If the water leakage is related to refueling operation, provide information regarding the corrosion susceptibility of the cylindrical part of the drywell shell on the insulation (inaccessible) side. c.Item No. E4.12 of Examination Category E-C of Subsection IWE requires the owner to establish grid and measurement locations in the suspect areas identified for augmented
 
examinations. Provide information regarding the methods used to establish a confidence
 
level that no drywell shell corrosion exists in the sand-pocket areas.
3-309  d.Unless preventive actions are taken and conditions verified that no leakage and shell corrosion exists in the suspect areas, IWE will require continuation of UT measurements
 
in the augmented examination areas. Provide justification for excluding the suspect areas from augmented examinations. e.Based on the results of the UT examinations performed from the accessible areas of the drywells, BFN asserted that the condition of the drywell shells is good. Provide a
 
discussion of BFN's criteria for judging that the condition of the drywell steel liner plate is
 
good and the rationale for the criteria. f.Provide a discussion of any degradation observed and/or repair work implemented as a result of past general visual inspection of the moisture barrier located at the junction of
 
the steel drywell and the concrete floor.
In its response, by letter dated January, 31, 2005, the applicant stated:
a.See response to item "b."  b.A postulated failure of the drywell-to-reactor building refueling seal can result in water intrusion into the annulus space around the drywell. This leakage can occur only during
 
refueling outages when the reactor cavity is flooded to allow movement of fuel between
 
the reactor and the fuel pool. However, water intrusion does not cause failure of the
 
drywell's intended function. Any water leakage resulting from a postulated failure of the
 
drywell-to-reactor building refueling seal could not remain suspended in the annulus
 
region for an indefinite period of time and would eventually be routed to the sandpocket
 
area drains or would evaporate due to the heat generated in the drywell during
 
operation. In TVA's response to NRC Generic Letter 87-05 dated August 30, 1988, which addressed the potential for corrosion of boiling water reactor (BWR) Mark I steel
 
drywells in the "sand pocket region," TVA provided the NRC with the results of the
 
ultrasonic testing for corrosion degradation of drywell liner plate. The results of the
 
ultrasonic testing states: Each unit's drywell was ultrasonically tested near the sand
 
cushion area during 1987. The results from these tests showed that the nominal
 
thickness was maintained on each drywell. Below are the results of each unit's drywell
 
ultrasonic testing:
* Unit 1 - No reading below the nominal thickness of one inch was measured indicating that the integrity of the drywell liner plate is maintained. Periodic
 
leakage from the sand cushion area has been observed. Corrosive species in the
 
drainage are bases to suspect a higher rate of corrosion on Unit 1 drywell liner
 
plate than on Unit 2 and 3. However, objective evidence of serious corrosion
 
damage was not noted.
* Unit 2 - No reading below the nominal thickness of one inch was measured indicating that no damage to the integrity of the drywell liner plate has occurred.
* Unit 3 - No reading below the nominal thickness of one inch was measured indicating that no damage to the integrity of the drywell liner plate has occurred. c.In response to NRC Generic Letter 87-05, TVA provided the NRC with the results of the ultrasonic testing for corrosion degradation of BFN Units 1, 2, and 3 drywell liner plates
 
near the sand cushion area during 1987. The results from these tests showed that the
 
nominal thickness was maintained on each drywell. Paragraph IWE-1242 of ASME 3-310Section XI requires the Owner to determine containment surface areas requiring augmented examination, in accordance with Paragraph IWE-1241. UT thickness
 
measurements of this area were obtained during the U2C10 and U3C8 refueling outages
 
for Units 2 and 3 respectively and in 1999 and 2002 for Unit 1 (0-TI-376 Appendix 9.7
 
page 4). The data indicate that the condition of the drywell steel liner plate in this area
 
meets code requirements, and that this area should not be categorized for augmented
 
examination. d.See response to Item c.
e.See response to Item c.
f.The internal drywell steel containment vessel (SCV) embedment zone is subject to corrosion if the drywell floor-to containment vessel moisture barrier fails, allowing moisture intrusion, or if the concrete floor of the drywell cracks, allowing moisture
 
seepage through to the steel liner. During the Unit 2 Cycle 9 outage, a portion of the
 
moisture barrier was replaced (Problem Evaluation Report (PER) BFPER971516).
 
Engineering personnel performed an examinat ion of the exposed drywell SCV area below the moisture seal. This inspection indicated some minor pitting and localized rust, but nothing approximating a challenge to nominal wall thickness. No propagation of iron
 
oxide to the concrete surface was noted, which would be indicative of steel containment
 
vessel corrosion below the concrete. Inspections conducted by the Containment ISI
 
Program during Unit 2 Cycle 10 refueling outage and Unit 3 Cycle 9 refueling outage
 
also identified some damaged areas of the moisture barrier (gaps, cracks, low
 
areas/spots, or other surface irregularities) that were evaluated by engineering and
 
replaced or repaired. (PER 99-005254-000 for Unit 2 Drywell moisture seal barrier and
 
PER 00-004163-000 for Unit 3 Drywell moisture seal barrier).
In Unit 1, the moisture barrier in areas that would be made inaccessible due to ductwork installation have been replaced. Visual exam ination of exposed drywell SCV area below the moisture barrier identified some minor pitting. Ultrasonic thickness and pit depth
 
measurements were taken and evaluated by engineering which confirmed nominal wall thickness was not encroached. The entire Unit 1 moisture barrier will be replaced before
 
restart. The Structures Monitoring Program also monitors the concrete to ensure that it is free of penetrating cracks that provide a path for water seepage to the surface of the
 
containment shell. Research of plant history did not reveal any instances of water spills
 
and water ponding on the containment concrete floor. A general visual inspection of the
 
moisture barrier at the junction of the steel drywell shell and the concrete floor is performed once each inspection interval in accordance with the ASME Section XI, Subsection IWE aging management program.
Based on the responses, the staff understood that for each unit the applicant has taken actions to monitor corrosion of the outside surface of the drywell shell and the inside surface at the
 
junction of the concrete floor and the drywell shell. However, the extent of monitoring the
 
parameters associated with the degradation and the root cause(s) of the corrosion problems are
 
not clear.
The response to RAI 3.5-4 emphasizes that the existing degradation of the drywell shells (inside and outside) has not reached the minimum required thickness of one inch. However, the 3-311 response does not address a number of parameters that are pertinent to the period of extended operation. In a follow-up to RAI 3.5-4, dated April 5, 2005, the applicant was requested to
 
provide (1) a description of the type of degradation (e.g, a cluster of pits or general corrosion),
(2) a description of preventive actions (e.g. stopping the leaks from the refueling cavity seals or
 
monitoring of sand drains), (3) a description of corrective actions (repairing/cleaning and
 
recoating degraded areas), (4) a description of the extent of degradation, and (5) when
 
IWE-1240 requirement for augmented inspection will be implemented.
In its letter dated May 31, 2005, the applicant stated that during each refueling outage since the mid-1980s, a visual inspection of the interior surface of the drywell, and the interior and exterior
 
surface of the drywell head and torus (suppression chamber) was performed to verify structural
 
integrity. These inspections are performed per SI 0-SI-4.7.A.2.K, "Primary Containment Drywell
 
Surface Visual Inspection," and BFN Technical Instruction 0-TI-417, "Inspection of Service Level
 
I, II, III Protective Coatings." SI O-SI-4.7.A.2.K originally included the exam requirements for the
 
visual inspections of the protective coatings but was revised in March 2001 to remove those requirements and add the reference to BFN Technical Instruction 0-TI-417 for coating
 
inspections. BFN Technical Instruction 0-TI-417 was written to incorporate the information for
 
performing visual inspections of Service Level I protective coatings (design-basis accident (DBA) and non-DBA qualified).
This procedure was implemented in March 2001. The scope of SI 0-SI-4.7.A.2.K, as defined in the procedure, is as follows:    (1)Includes provisions for the visual verification of the structural components of the drywell, drywell head, torus (suppression chamber), and the exterior surfaces of the drywell head
 
and torus (suppression chamber) (i.e., piping, connections, structural supports, penetrations, platform steel, duct supports, concrete walls, and steel shell) by visually
 
inspecting for deterioration and/or structural damage.  (2)Provides visual inspection of the moisture seal barrier located on drywell elevation 550 feet.  (3)Provides for visual inspection of the interior surfaces of the drywell and torus (suppression chamber) above the level one foot below the normal water line and exterior
 
surface of the torus (suppression chamber) below the water line each operating cycle for
 
deterioration and any signs of structural damage with particular attention to piping
 
connections and supports and for signs of distress or displacement. In its response, the
 
applicant provided the results of the earlier inspections of the drywell internal
 
components for each unit.
Based on the detailed response, the staff found that the applicant has in place detailed procedures for examining the concrete and steel components inside the drywell, and systematic acceptance criteria. The applicant plans to continue this process during the extended period of
 
operation. Therefore, the staff found the applicant's process of detecting degradation of these
 
components adequate and acceptable, and the staff's concern described in RAI 3.5-4 is
 
resolved.In RAI 3.5-5, dated December 10, 2004, the staff stated that a number of load-bearing reinforced concrete structures within the drywell shell were subjected to temperatures higher than the established threshold of 150 &deg;F, as discussed in LRA Section 3.5.2.2.2.1. The
 
effectiveness of the closed cooling ventilati on system is paramount in preventing large 3-312 temperature excursions in the drywells. Therefore, the staff requested that the applicant provide the following information related to the concrete structures within the drywells of each unit. a.Provide a summary of the operating experience related to the reliability of the closed cooling ventilation system. b.Provide a summary of the results of the last inspections performed on (1) reactor pressure vessel (RPV) pedestal supports, (2) the foundation and floor slab, and (3) the
 
sacrificial shield wall under the existing Structural Monitoring Program. c.LRA Section 3.5.2.2.2.1, Item 8, states that the main steam tunnels in the reactor building at Units 1, 2, and 3 have a maximum normal space ambient temperature of 160 &deg;F. Provide a discussion, including a summary of the results of the engineering
 
analysis performed, to support the conclusion that the conditions identified in the GALL
 
Report are satisfied and that aging management of reduction of strength and modulus
 
due to elevated temperature for the affected concrete components is not required.
In its response, by letter dated January 31, 2005, the applicant stated:
Note that LRA Section 3.5.2.2.2.1, Item 8 states in part: "The upper elevations of thesacrificial shield wall may exceed 150 &deg;F briefly and infrequently, during abnormal
 
operations and is not considered to affect its function." The upper elevation of the
 
sacrificial shield wall inside the drywell shell is not a load bearing reinforced concrete
 
structure. a.The drywell closed cooling ventilation system is a non-safety related system and not in scope for License Renewal. This function is not required for Safe
 
Shutdown of the plant. If this cooling system function is lost, operator action will
 
be required when the Technical Specifications for drywell temperature limits exceeds 150 &deg;F. b.A review of Browns Ferry Structures Monitoring Baseline inspection and the results for the first Structures Monitoring inspection period did not reveal any loss
 
of intended function due to aging effects of the RPV pedestal supports, the
 
foundation and floor slab, and the sacrificial shield wall. c.Appendix A of ACI 349-85 specifies that the concrete temperature limits fornormal operation or any other long term period shall not exceed 150 &deg;F except for
 
local areas, which are allowed to have increased temperatures not to exceed 200 &deg;F. With the exception of the main steam tunnels in the Reactor Building, BFN reinforced concrete structures have general area temperatures less than
 
150 &#xba;F during normal operation. The general area temperatures have been
 
conservatively evaluated using maximum normal space ambient temperatures
 
noted on the Harsh Environmental drawing series and associated calculations.
 
The Unit 1, 2, and 3 main steam tunnels at BFN have a maximum normal space
 
ambient temperature of 160 &#xba;F as noted in the Harsh Environmental drawing
 
series and associated calculations. Note however, that this is a maximum normal
 
space ambient temperature. The TVA Harsh Environmental drawing series and
 
associated calculations identify the average normal space ambient temperature
 
as 135 &#xba;F. This is judged to be acceptable because when concrete is subjected
 
to prolonged exposure to elevated temperatures, reductions in excess of 10 3-313 percent of the compressive strength, tensile strength, and the modulus of elasticity only begin to occur in the range of 180 &#xba;F to 200 &#xba;F. (Reference EPRI
 
TR-103842, July 1994).
Therefore, the conditions identified in NUREG-1801 are satisfied and aging management of reduction of strength and modulus due to elevated temperature
 
for concrete components at BFN is not required.
The staff recognizes the temperature thresholds, and accepts the EPRI TR position. However, at these temperatures, the concrete structures go through additional shrinkage cracking, and
 
spalling. The staff's basic concern was related to the degradation of pedestals supporting the
 
reactor vessels and that of the seismic restraints anchored to the sacrificial shields and the
 
drywell. The staff expected more description regarding the concerns in response to item "b." In
 
this context, in a follow up letter, April 5, 2005, the applicant was requested to provide (1) the
 
type and extent of degradation observed in the reactor pedestals and at the seismic restraint
 
anchorage areas, and (2) the acceptance standards established (e.g., ACI 349-3R, ASME Code
 
Subsection IWE) for corrective actions.
In its response, by letter May 24, 2005, the applicant stated that the inspection of concrete within the drywell is conducted per BFN "Procedure Walkdown of Structures for Maintenance Rule" (LCEI-CI-C9). This LCEI provides the basis for monitoring/inspection tasks, examination
 
criteria, evaluation requirements, and acceptance criteria in compliance with the Maintenance
 
Rule. A baseline inspection was established in 1997 and subsequent inspections are performed
 
on a five-year frequency. LCEI-CI-C9 Section 7.2 provides inspection guidelines, and visual
 
inspections of structural conditions are used to detect degradation. Visual inspection is an
 
acceptable technique and is consistent with techniques identified in industry codes and
 
standards such as ACI 349.3R-96. Inspection checklists (LCEI-CI-C9 Attachment 1) are used to
 
document inspection results/defects.
LCEI-CI-C9 Section 7.3 provides guidance for evaluation of the results documented on the inspection checklists. The acceptance criteria are defined in LCEI-CI-C9 Section 7.3 as: (1)
 
acceptable, (2) acceptable with deficiencies, and (3) unacceptable. The latest inspection of the
 
concrete of the reactor vessel support pedestal, biological or sacrificial shield wall, and other
 
structural concrete within the primary containment structure had been completed by 2002 for
 
Units 2 and 3. All concrete elements within the primary containment structure for Units 2 and 3
 
were found to be acceptable.
The staff found the inspection procedure used to detect deterioration of the concrete structures inside drywell adequate and acceptable, as its continued use during the period of extended
 
operation will ensure the intended functions of these components. Therefore, the staff's concern
 
described in RAI 3.5-5 is resolved.
In RAI 3.5-6, dated December 10, 2004, the staff stated that LRA Table 3.5.2.26 is silent on theAMR related to Class MC supports. ASME Section XI Subsection IWE Program takes exception to NUREG-1801 Section XI.S3, and states that the aging effects for supports of MC
 
components will be managed by the Structures M onitoring Program or Chemistry Control Program with associated One-Time Inspection Program for submerged supports during the
 
extended period of operation. Therefore, the staff requested that the applicant provide the
 
following information related to the aging management of Class MC supports:
3-314
* Provide the results of the AMR for (1) MC component supports within the BFN containments, (2) MC component supports outside the containments, and (3) supports
 
for piping penetrating through the containments and designated as MC piping (if any).
 
Also, summarize the program (sample size, inspection frequency, personnel
 
qualification, etc.) used to arrive at the AMR results.
* Section 50.55a(g)(4) of 10 CFR requires the inservice inspections of Class MC pressure retaining components and their integral attachments, in accordance with the requirements of ASME Code Section XI. ASME Code Section XI Subsection IWF sets
 
the examination requirements for Class MC supports, other than those for the MC piping
 
supports. Therefore, provide justification for the exception taken in ASME Code Section XI Subsection IWF Program regarding the aging management of Class MC
 
component supports.
* Subsections IWE and IWF do not incorporate explicit requirements for inservice inspection of supports of pipes designated as Class MC; therefore, the applicant was
 
requested to provide a description of a proposed AMP (could be part of the Structural
 
Monitoring Program), including sample size, the extent of examination, frequency of
 
examination, and qualification of personnel who perform and evaluate the inspection
 
results.In its response, by letter dated January 31, 2005, the applicant noted that the information requests made in RAI 3.5-6 are addressed in the responses to RAIs 2.4-2, 2.4-13(a) & (b) and
 
B.2.1.33, dated January 24, 2005. Finally, by letter dated May 31, 2005, the applicant agreed to
 
bring the inspection and inspector qualification with regards to Class MC supports into the scope of ASME Section XI Subsection IWF Program (see SER Section 3.0.3.2.21 for staff evaluation of the ASME Section XI Subsection IWF Program). After comprehensively reviewing
 
all responses to the indicated RAIs, above, the staff concluded that the applicant had
 
successfully resolved all of the staff issues with regard to this and the other RAIs indicated.
The staff also reviewed the information provided in LRA Section 3.5.2.1.1 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects, for the primary containment structures components that are not
 
addressed by the GALL Report. The staff found the applicant's AMR results for the primary
 
containment structures components acceptable.
3.5.2.3.2  Reactor Buildings - Summary of Aging Management Evaluation - Table 3.5.2.2
 
The staff reviewed LRA Table 3.5.2.2, which summarizes the results of AMR evaluations for the reactor buildings component groups.
During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.2, for MEAP combinations that are not consistent with the GALL Report. The staff requested clarifications for
 
the following material/environment combinations and the corresponding LRA Table 2 items:
Ceramic Fiber in an Inside Air Environment - The staff requested that the applicant provide the BFN technical basis for concluding that no aging management is required for ceramic fiber fire
 
barriers in an inside air environment.
The following list identifies the ceramic fiber components in an inside air environment:
3-315
* reactor building fire barriers
* diesel generator building fire barriers By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that ceramic and glass fiber used to seal fire barrier penetrations do not have any applicable
 
aging effects requiring aging management. This is consistent with previous staff positions in that
 
there are no applicable aging effects for glass used in a metal fire barrier penetration. This is
 
also consistent with the NUREG-1769 "Safety Evaluation Report Related to License Renewal of Peach Bottom Atomic Power Station, Units 2 and 3," dated January 31, 2003,which concurred
 
that insulation made of aluminum, stainless steel (mirror), calcium silicate, ceramic fiber, or
 
fiberglass in a sheltered environment does not have any aging effects requiring aging
 
management.
The applicant further stated that a review of BFN operating history did not reveal any loss of intended function due to aging effects for the following ceramic fiber components.
* reactor building fire barriers
* diesel generator building fire barriers The staff concluded that the applicant had not credited an existing AMP (structures monitoring and/or fire protection) that already includes fire barriers in its scope, on the basis that its AMR
 
did not identify any applicable aging effects.
Earthfill & Rock in a Buried Environment - This item indicates that the equipment supports and foundations are earth fill (rock and sand). The staff requested that the applicant explain the
 
technical bases for concluding that there are no aging effects requiring management.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the foundation for the condensate water storage tank (CWST) is comprised of a concrete
 
ring foundation with the interior portion of the ring foundation filled with crushed rock and sand.
 
The earthen materials (rock and sand) of the CWST foundation interior base are protected from
 
environmental weathering conditions by the concrete perimeter ring and CWST tank bottom.
 
There are no aging effects for the earthen materials of the CWST foundation interior base that
 
require aging management. Aging management of the CWST concrete foundation ring is
 
managed by the Structures Monitoring Program. Aging management of the CWST bottom will be performed by the One-Time Inspection Program.
The applicant also stated that a review of BFN operating history did not reveal any loss of intended function due to aging effects for earthen materials of the CWST foundation interior
 
base. Based on the additional information provided by the applicant, the staff concurred with the applicant's AMR results for the crushed rock and sand base of the CWST. The staff concluded
 
that aging management is not required because these materials are adequately protected by
 
the concrete perimeter ring and the CWST tank bottom.
Elastomers in an Embedded/Encased Environment - The staff requested the applicant to clarify whether the compressible joints and seals that are embedded/encased in concrete are 3-316 accessible for monitoring. If not, the staff requested the applicant to explain how the Structures Monitoring Program is utilized to manage aging effects in inaccessible areas.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that LRA Table 3.5.2.2, rows 4 and 5, apply to the seal around the reactor building access
 
doors. Row 4 applies to the portion of the seal that is embedded/encased, and row 5 applies to
 
the portion of the seal that is exposed to the inside air environment of the reactor building. An
 
embedded/encased environment will minimize aging effects due to elastomer degradation
 
caused by inside air environment (ambient conditions of ultraviolet radiation, ozone, temperature, etc.). The Structures Monitoring Pr ogram will periodically inspect the portion of the seal that is exposed to the inside air environment of the reactor building for aging effects due to
 
elastomer degradation. The condition of the exposed portion of the seal will provide an
 
indication of the condition of the embedded/encased portion of the seal. The inaccessible
 
portions of the embedded/encased seal for the reactor building access door will be monitored
 
with the periodic inspections of the seal that are exposed to the air environment of the reactor
 
building.Based on the additional information provided by the applicant, the staff finds the applicant's AMR results for the embedded/encased portion of the seal around the reactor building access
 
doors to be acceptable. The condition of the exposed portion of the seal will be periodically
 
inspected by the Structures Monitoring Program, which will provide an indication of the condition of the embedded/encased portion of the seal.
Stainless Steel in an Embedded/Encased Environment
- All metals embedded/encased in concrete are inaccessible; however, they could be susceptible to aging degradation. The staff
 
requested that the applicant provide an AMR to further evaluate embedded/encased
 
components if aging of components in accessible areas is identified that may indicate aging of
 
the inaccessible components.
The following list identifies stainless steel components that are embedded/encased:
* mechanical penetrations
* spent fuel pool liners By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the BFN concrete structures and concrete components are designed in accordance with
 
ACI 318-63 and 71 and constructed using ingredients conforming to ACI and ASTM standards, which provide for a good quality, dense, well-cured, and low permeability concrete. Cracking is
 
controlled through proper arrangement and distribution of reinforcing bars. Concrete structures
 
and concrete components are constructed of a dense, well-cured concrete with an amount of
 
cement suitable for strength development, and achi evement of a water-to-cement ratio that is characteristic of concrete having low permeability. This is consistent with the recommendations
 
and guidance provided by ACI 201.2R-77.
The applicant also stated that the AMR for the material and environment combination of stainless steel in an embedded/encased environment was performed and concluded that no
 
aging mechanism was identified that requires management. The applicant noted that the
 
submerged surfaces of spent fuel pool liner s are managed by the Chemistry Control Program and monitoring of the spent fuel pool level is managed by plant operations.
3-317 The applicant further stated that a review of BFN operating history did not reveal any loss of intended function due to aging effects for stainless steel mechanical penetrations or spent fuel
 
pool liners that are embedded/encased in concrete.
The staff found that the applicant had identified an appropriate course of action to manage aging of stainless steel submerged surfaces of spent fuel pool liners because it is consistent
 
with the guidance in the GALL Report. For other stainless steel structural components
 
embedded/encased in concrete, the staff accepted the applicant's AMR results that aging
 
management is not required, because stainless steel structural components in general are not
 
susceptible to degradation, and concrete provides protection for embedded/encased steel.
The staff's review of LRA Table 3.5.2.2 identified areas in which additional information was necessary to complete the review of the applicant's results. The applicant responded to the
 
staff's RAIs as discussed below.
In RAI 3.5-7, dated December 10, 2004, the staff stated that the buried environment item in LRA Table 3.0.2 states that ground water is non-aggressive. Therefore, the staff requested that the
 
applicant provide historical site ground water chemistry test results together with a discussion of
 
the extent of past ground water sampling and testing frequency, as well as the extent of
 
fluctuation of the test results to support the above assertion.
In its response, by letter dated January 31, 2005, the applicant stated:
Since BFN did not have data available from the construction period or since plant start-up, baseline sampling was performed over the past year of groundwater and the
 
Wheeler Reservoir. The baseline sampling was to establish if BFN had aggressive or
 
non-aggressive water as defined by the following criteria: pH <5.5, Chlorides > 500 ppm
 
and Sulfates > 1500 ppm. The samples were taken at intervals to take into consideration
 
seasonal variations. The samples were taken from the existing site radiological
 
monitoring wells and from the Wheeler Reservoir in close proximity to the Intake
 
Pumping Station structure. Samples were taken at various depths in the monitoring well
 
and the Reservoir by the site environment staff and analyzed by an off-site laboratory for
 
the site environment group. Results of Browns Ferry groundwater and Wheeler
 
Reservoir water sampling are as follows:
 
a.Groundwater:
* pH ranges from 6.33 to 8.77 which are well above <5.5 (Note in the well that the value 6.33 was obtained, the remaining pH readings ranged from 7.16 to 7.60 during the time period of sampling. Only one other well had a pH value below 7 and its pH was 6.92 with the remaining readings ranging between 7.12 and 7.6)
* Chlorides - maximum reading of 18.3 ppm which is well below the threshold of 500 ppm
* Sulfates-maximum reading of 30.3 ppm which is well below the threshold of 1500 ppm  b.Wheeler Reservoir:
3-318
* pH ranges from 7.28 to 8.64 which are well above < 5.5
* Chlorides - maximum reading of 13.9 ppm which is well below the threshold of 500 ppm
* Sulfates - maximum reading of 15.5 ppm which is well below the threshold of 1500 ppm Browns Ferry groundwater and Wheeler Reservoir sample measurements have confirmed that parameters are well below threshold limits that could cause concrete
 
degradation (i.e., an aggressive environment does not exist).
Based on the above test data, the staff found that both the Browns Ferry groundwater and the Wheeler Reservoir water are non-aggressive. Therefore, the staff's concern described in
 
RAI 3.5-7 is resolved.
In RAI 3.5-8, dated December 10, 2004, the staff stated that the AMR discussion provided in LRA Section 3.5.2.2.2.2 is rather general and brief, and requires more detailed elaboration to
 
support BFN's conclusion that the conditions identified in the GALL Report, as revised by
 
ISG-03, are satisfied and no aging management for below-grade inaccessible concrete is
 
needed. Therefore, the staff requested that the applicant provide additional specific information, including: (1) concrete quality and test data for inaccessible concrete, (2) past operating
 
experience regarding exposure of inaccessible concrete to aggressive chemical/fluid
 
environment, and (3) past inaccessible concrete inspection findings and data related to concrete
 
degradation and repairs.
In its response, by letter dated January 31, 2005, the applicant stated:  (1)The BFN concrete structures and concrete components are designed in accordance with ACI 318-63 and 71 and constructed using ingredients conforming to ACI and ASTM
 
standards, which provide for a good quality, dense, well cured, and low permeability
 
concrete. Cracking is controlled through proper arrangement and distribution of
 
reinforcing bars. Concrete structures and concrete components are constructed of a
 
dense, well-cured concrete with an amount of cement suitable for strength development, and achievement of a water-to-cement ratio that is characteristic of concrete having low
 
permeability. This is consistent with the recommendations and guidance provided by ACI
 
201.2R-77.    (2)As noted in the response to RAI 3.5-7, Browns Ferry groundwater water and Wheeler Reservoir sample measurements have c onfirmed that parameters are well below threshold limits that could cause concrete degradation (an aggressive environment does
 
not exist).  (3)A review of Browns Ferry operating history, the Browns Ferry Structures Monitoring Baseline inspection, and the results for the first Structures Monitoring inspection period
 
did not reveal any loss of intended function due to aging effects when below-grade
 
inaccessible concrete was excavated for other reasons.
Based on the plant-specific operating experience reported in item 3 and the fact that the applicant complied with applicable provisions of the GALL Report, the staff found the applicant's
 
response acceptable, and the staff's concern described in RAI 3.5-8 is resolved.
3-319 In RAI 3.5-9, dated December 10, 2004, the staff stated that in LRA Table 3.5.2.2, no AERM and AMPs are identified for hatches/plugs, and electrical and instrumentation and control (I&C)
 
penetrations made of carbon and low-alloy steel that are embedded or encased in concrete;
 
whereas, GALL Report Item III.A2.2-a calls for a Structures Monitoring Program to manage the
 
loss of material and corrosion aging effects for steel components exposed to various
 
environments. Additionally, the mechanical penetrations listed in Table 3.5.2.2 and the
 
structural steel beams, columns, plates, and trusses that are embedded or encased in concrete
 
are also identified as having no applicable aging effect that requires aging management;
 
therefore, no AMP is designated for the components. This same BFN position is shown
 
throughout the remainder of LRA Table 3.5.2.2. Therefore, the staff requested the applicant to
 
discuss past operating experience and inspection results related to aging degradation of
 
embedded or encased hatches, plugs, duct banks, manholes, mechanical penetrations, and
 
electrical and I&C penetrations in order to provide an operating experience-based rationale to
 
justify its assertion that these components require no AMP to manage their aging.
In its response, by letter dated January 31, 2005, the applicant stated:
The BFN concrete structures and concrete components are designed in accordance with ACI 318-63 and 71 and constructed using materials conforming to ACI and ASTM
 
standards, which provide for a good quality, dense, well cured, and low permeability
 
concrete. Cracking is controlled through proper arrangement and distribution of
 
reinforcing bars.
Concrete structures and concrete components are constructed of a dense, well-cured concrete with an amount of cement suit able for strength development, and achievement of a water-to-cement ratio that is characteristic of concrete having low permeability. This
 
is consistent with the recommendations and guidance provided by ACI 201.2R-77. As a
 
minimum, all exposed portions of embedded carbon steel structural components are
 
inspected for the following aging effects:
* Outside Air Environments: Loss of material due to general and pitting corrosion
* Inside Air Environments: Loss of material due to general corrosion
* Containment Air Environments: Loss of material due to general corrosion
 
A review of Browns Ferry operating history, the Browns Ferry Structures Monitoring Baseline inspection, and the results for the first Structures Monitoring inspection period
 
did not reveal any loss of intended function due to aging effects for carbon steel
 
components embedded/encased in concrete.
Based on the above plant-specific operating experience and the fact that concrete structures and concrete components are designed in accordance with ACI 318-63 and 71 and constructed
 
using materials conforming to ACI and ASTM standards, which provide for a good quality, dense, well-cured, and low permeability concrete, the staff found that the applicant had
 
adequately justified its AMR results regarding the concrete elements listed in LRA Table 3.5.2.2.
 
Therefore, the staff's concern described in RAI 3.5-9 is resolved.
In RAI 3.5-10, dated December 10, 2004, the staff noted that non-ferrous aluminum electrical and I&C penetrations embedded or encased in concrete are listed in the second item of LRA 3-320 Table 3.5.2.2 as components requiring no AMP to manage any aging effect. Therefore, the staff requested the applicant to provide a discussion of past and applicable industry operating
 
experience to justify this AMR finding. Additionally, referring to embedded or encased stainless
 
steel spent fuel pool liners listed in LRA Table 3.5.2.2, the applicant was requested to discuss
 
applicable operating experience of these liners to justify its AMR results that no AMP is needed
 
to manage any aging effect.
In its response, by letter dated January 31, 2005, the applicant stated:
The BFN concrete structures and concrete components are designed in accordance with ACI 318-63 and 71 and constructed using materials conforming to ACI and ASTM
 
standards, which provide for a good quality, dense, well cured, and low permeability
 
concrete. Cracking is controlled through proper arrangement and distribution of
 
reinforcing bars.
Concrete structures and concrete components are constructed of a dense, well-cured concrete with an amount of cement suit able for strength development, and achievement of a water-to-cement ratio that is characteristic of concrete having low permeability. This
 
is consistent with the recommendations and guidance provided by ACI 201.2R-77.
Embedded or Encased Aluminum Response
: Aluminum is a reactive metal, but it develops an aluminum oxide film that prot ects it from further corrosion in an indoor environment. The specific aluminum alloy (6063-T42) used at BFN for conduit and
 
raceways is resistant to general corrosion, pitting, and SCC during testing in outdoor, and saltwater environments. For the aluminum that is embedded/encased within the
 
concrete, corrosion is not considered an applicable aging mechanism. The concrete
 
must first be degraded by other aging mechanisms, which reduce the protective cover
 
and potentially allow for the intrusion of aggressive ions causing a reduction in concrete
 
pH. Aging management of concrete aging effects will manage the corrosion of the
 
embedded/encased aluminum's concrete protective cover. A review of Browns Ferry
 
operating history, the Browns Ferry Structures Monitoring Baseline inspection, and the
 
results for the first Structures Monitoring inspection period did not reveal any loss of
 
intended function due to aging effects for aluminum components embedded/encased in
 
concrete.Embedded or Encased Stainless Steel Response
: For the stainless steel that is embedded/encased within the concrete, corrosion is similarly not considered an
 
applicable aging mechanism. The concrete must first be degraded by other aging
 
mechanisms, which reduce the protective cover and allow for the intrusion of aggressive
 
ions causing a reduction in concrete pH. Adequate management of other concrete aging
 
effects will in effect manage the aging of the embedded/encased stainless steel. After a
 
review of the Browns Ferry operating history, the Browns Ferry Structures Monitoring
 
Baseline inspection, and the results for the first Structures Monitoring inspection period
 
did not reveal any loss of intended function due to aging effects for stainless steel that is
 
embedded/encased within concrete. Operating history did show a small leak in the
 
Unit 1 fuel pool liner. The Unit 1 fuel pool has remained in service during the extended
 
outage since spent fuel is stored in the pool. This leak in the Unit 1 fuel pool was
 
documented in accordance with the site's Corrective Action Program, SPP-3.1, Tennessee Valley Authority Nuclear (TVAN) Standard Program and Processes, "Corrective Action Program" as PER 00- 011982-000 (electronic corrective action 3-321 program number 35486. This leak is contained within the leak channel beneath the fuel pool liner). The fuel pool liners are monitored on a monthly basis per operation
 
instruction 1-OI-78. The leak is small (~0.06 gpm)and has been steady over time without
 
an increasing trend over the last ten years.
The staff found the above applicant's justification reasonable and adequate because it was supported by the fact that the operating history, structures monitoring baseline inspection, and
 
results from the first structures monitoring inspection period did not reveal any loss of intended
 
function due to aging effects for aluminum and stainless steel embedded or encased within
 
concrete. Therefore, the staff's concerns described in RAI 3.5-10 are resolved.
In RAI 3.5-14, dated December 10, 2004, the staff stated that, with respect to the neutron-absorbing sheets in spent fuel storage racks, as described in LRA Section 3.3.2.2, the
 
applicant stated that the Chemistry Control Program manages general corrosion and that an
 
inspection of Boral coupon test specimens was performed at BFN that confirmed that no
 
significant aging degradation had occurred and that the neutron-absorbing capacity of the Boral
 
had not been reduced. Since it is implied that some Boral aging degradations had occurred at the time of inspection of the test specimens, the staff requested the applicant to discuss the basis for the above assertion that the neutron-absorbing capacity of the Boral will be maintained at an adequate level during the extended period of plant operation.
In its response, by letter dated January 31, 2005, the applicant stated:
A total of 16 boral coupons were placed in the Unit 3 spent fuel storage pool (SFSP) in October 1983. The coupons supplied by the rack manufacturer are of the same
 
metallurgical condition as the high density fuel storage racks (HDFSR) in thickness, chemistry, finish, and temper. For the first six years of the planned fifteen year
 
surveillance program, examination was to have taken place at two-year intervals.
Accordingly, two coupons were removed in October 1985. Blisters were found upon
 
examination, and because of this unexpected anomaly, three additional coupons were
 
analyzed not finding any blisters. As a result of blisters found on the coupons removed in
 
1985, the surveillance program has been expanded to include monitoring the formation
 
and behavior of these blisters. These boral coupons are periodically removed from the
 
fuel pool for testing and are evaluated for corrosion or other degradation of the neutron
 
absorber plates by comparing various physical characteristics of the test coupons to
 
baseline measurements taken when the coupons were installed. Also, a metallurgical
 
engineer examines the coupons for general corrosion, local pitting, and bonding. No
 
further blisters, corrosion, or degradation has been identified in coupons evaluated
 
through 2003.
The above response states that these Boral coupons are periodically removed from the fuel pool for testing and are evaluated for corrosion or other degradation of the neutron absorber
 
plates by comparing various physical characteristics of the test coupons to baseline
 
measurements taken when the coupons were installed. The response also implies that a
 
metallurgical engineer periodically examines the coupons for general corrosion, local pitting, and bonding. Also, no further blisters, corrosion, or degradation have been identified in coupons
 
evaluated through 2003; however, it was not clear to the staff whether these periodic
 
inspections are ongoing activities that are an extension of the 1983 Boral Coupon Inspection
 
Program covering Boral coupon test specimens or a separate AMP in addition to the Chemistry 3-322 Control Program mentioned above. The applicant was requested to clarify the key parameters of this periodic inspection program or activity including the objective, scope, frequency, and
 
inspection approach of the program.
In its response, by letter May 24, 2005, the applicant stated that:
The Boral coupon inspection program was initiated in 1983 to implement the inspection and testing requirements of UFSAR Section 10.3.6; this checks the long-term behavior
 
of the material of the high density spent fuel racks. The inspection is performed per BFN
 
Technical Instruction (TI) TI-116, "High Density Fuel Storage System Surveillance
 
Program." When the TI is performed, Boral coupons are removed from the spent fuel
 
storage pool and examined by the Metallurgical Engineer in their original condition to
 
determine if sampling of surface corrosion products is appropriate. Thickness
 
measurements are obtained of each coupon and documented in accordance with the TI.
 
If degradation is such that further investigation is warranted, a minimum of one coupon is
 
selected to be unsheathed or opened. Prior to the unsheathing process, a dye penetrant
 
test for indications on the outer surfaces of the coupon will be performed and is
 
examined by the Metallurgical Engineer. The Metallurgical Engineer decides if further
 
unsheathing of the coupons is required. The visual examination by the Metallurgical
 
Engineer is documented on the appropriate forms of the TI. The current frequency for
 
performing this TI is two years. The surveillance frequency is re-evaluated each time the
 
surveillance is performed and can be changed based on the trend of the historical data
 
results. The inspection of the Boral coupons will continue until such time as the trend of
 
the historical data results collected provides a basis to discontinue the inspections.
Based on its review, the staff found the applicant's response to RAI 3.5-14 acceptable.
Therefore, the staff's concern described in RAI 3.5-14 is resolved.
In RAI 4.7.4-1, dated December 10, 2004, LRA Table 3.5.2.2 lists the AMR results of expansion joint (elastomer, polyurethane foam) as a TLAA and refers the TLAA to LRA Section 4.7. LRA
 
Section 4.7.4, "Radiation Degradation of Drywell Expansion Gap Foam," states that an analysis
 
of the effect of dose on the foam showed the material properties will remain within the limits
 
assumed by the original design analysis for the additional 20 years of extended operation.
 
Therefore, the staff requested the applicant to provide a more detailed discussion of the
 
analysis including a discussion of the assumptions adopted in the analysis, the type of data
 
extrapolation applied, and the quantitative results obtained to justify the assertion that the
 
requirements of 10 CFR 54.21(c)(1)(i) are fully met.
By letter dated January 31, 2005, the applicant provided its response to RAI 4.7.4-1. The staff evaluation of the applicant's response is provided in SER Section 4.7.4.
In RAI 3.5-17, dated March 25, 2005, the staff stated that LRA Table 3.5.2.29, Radwaste Building, has three separate rows of component type listings (i.e., reinforced concrete, beams, column, walls, and slabs) which make references to note I,1 (last column of the table) and are
 
shown to be associated with NUREG-1801 Section III.A3.1-h, Volume 2. Note I,1 of the table
 
implies that the radwaste building is founded on rock or bearing piles. The note also refers to
 
LRA Section 3.5.2.2.2.1 for further evaluation. Item 5 of the section does not clearly indicate
 
that the radwaste building is founded on rock or bearing piles. Therefore, the staff requested
 
that the applicant provide the type of foundation medium that supports the building; and if the 3-323 structure is not founded on rock or piles, to discuss the basis for asserting that the cracking, distortion, and increase in component stress level due to settlement are not aging effects
 
requiring management. The applicant was also asked, as appropriate, to revise LRA
 
Sections 3.5.2.1 and 3.5.2.2.2.1 to include the radwaste building within the scope of its
 
discussion.
In its response, by letter April 14, 2005, the applicant stated:
The Radwaste Building is founded on piles as noted by the entry under "Component Type" - "Piles" in Table 2.4.7.8.
LRA Section 3.5.2.2.2.1, Item 5, paragraph 1 on page 3.5-43 should be revised to read:
"Cracks, distortion, increase in component stress level due to settlement are not considered as aging effects requiring management for BFN structures founded
 
on rock or bearing piles. The following BFN structures are founded on rock or
 
bearing piles: Reactor Buildings, Primary Containments, Intake Pumping Station, Reinforced Concrete Chimney, Off-Gas Treatment Building, Equipment Access Lock, Turbine Buildings, Gate Structure Number 3, Diesel HPFP House, Transformer Yard, RHRSW Tunnel and Radwaste Building. Based on industry
 
experience, settlement of Class 1 structures founded on bedrock or bearing piles
 
have not been noted to cause aging effects requiring management."
Based on its review, the staff found the applicant's response to RAI 3.5-17 acceptable.
Therefore, the staff's concern described in RAI 3.5-17 is resolved.
In RAI 3.5-18, dated March 25, 2005, the staff stated that in its review of LRA Table 3.5.2.30, it was not clear as to whether the Group 5 category referred to includes the service building.
 
Therefore, the staff requested that the applicant confirm that the service building, or portion of
 
the service building, is clearly included within the scope addressed by LRA Section 3.5.2.2.2.1
 
and make any necessary revision to the LRA section to clarify its position.
In its response, by letter dated April 14, 2005, the applicant stated:
The aging management review of the Service Building was performed to the requirements for Group 3 Structures of NUREG-1801, Vol. 2, Chapter III.A3. The
 
Service Building is included within the scope addressed by LRA Section 3.5.2.2.2.1, Item
 
8 since it was considered as a Group 3 Structure and that section is applicable to Group
 
1 through Group 5 Structures of NUREG-1801, Vol. 2 Chapter 3.
The staff found the above response acceptable. Therefore, the staff's concern described in RAI 3.5-18 is resolved.
The staff also reviewed the information provided in LRA Section 3.5.2.1.2 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects, for the reactor buildings' components that are not addressed by the GALL Report. The staff found the applicant's AMR results for the service building components
 
acceptable.
3-324 3.5.2.3.3  Equipment Access Lock - Summary of Aging Management Evaluation - Table 3.5.2.3 The staff reviewed LRA Table 3.5.2.3, which summarizes the results of AMR evaluations for the equipment access lock component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.3 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects, for the equipment access lock components that are not addressed
 
by the GALL Report. The staff found the applicant's AMR results for the equipment access lock
 
components acceptable.
3.5.2.3.4  Earth Berm - Summary of Aging Management Evaluation - Table 3.5.2.4
 
The staff reviewed LRA Table 3.5.2.4, which summarizes the results of AMR evaluations for the earth berm component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.4 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects, for the earth berm components that are not addressed by the GALL
 
Report. The staff found the applicant's AMR results for the earth berm components acceptable.
3.5.2.3.5  Diesel Generator Buildings - Summary of Aging Management Evaluation -
Table 3.5.2.5 The staff reviewed LRA Table 3.5.2.5, which summarizes the results of AMR evaluations for the diesel generator buildings component groups.
During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.26, for MEAP combinations that are not consistent with the GALL Report. The staff requested clarifications for
 
the following material/environment combinations and the corresponding LRA Table 2 items:
Ceramic Fiber in an Inside Air Environment - The staff requested that the applicant provide the BFN technical basis for concluding that no aging management is required for ceramic fiber fire
 
barriers in an inside air environment.
The following list identifies ceramic fiber components in an inside air environment:
* reactor building fire barriers
* diesel generator building fire barriers By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that ceramic and glass fiber used to seal fire barrier penetrations do not have any applicable
 
aging effects requiring aging management. This is consistent with previous staff positions in
 
LRA SER concurrences that there are no applicable aging effects for glass used in a metal fire
 
barrier penetration. This is also consistent with the NUREG-1769 SER related to the license
 
renewal of another plant which concurred that insulation made of aluminum, stainless steel (mirror), calcium silicate, ceramic fiber, or fiberglass in a sheltered environment does not have
 
any aging effects requiring aging management.
3-325 The applicant further stated that a review of BFN operating history did not reveal any loss of intended function due to aging effects for the following ceramic fiber components.
* reactor building fire barriers
* diesel generator building fire barriers The staff concluded that the applicant had not credited an existing AMP (structures monitoring and/or fire protection) that already included fire barriers in its scope on the basis that its AMR
 
did not identify any applicable aging effects.
The staff's review of LRA Table 3.5.2.5 identified an area in which additional information was necessary to complete the review of the applicant's results. The applicant responded to the
 
staff's RAI, as discussed below.
In RAI 3.5-11, dated December 10, 2004, the staff stated that, with respect to the fire barriers consisting of ceramic fiber listed in LRA Table 3.5.2.5, the applicant's AMR identified neither
 
AERM nor AMP for the ceramic fiber fire barriers. Therefore, the staff requested that the
 
applicant discuss past plant-specific inspection results of these fire barriers in order to provide
 
an operating experience-based justification for the above AMR finding.
In its response, by letter dated January 31, 2005, the applicant stated:
This same RAI was asked as RAI 3.3-2 for the Reactor Building. In the response to that RAI, the same material was also addressed for the Diesel Generator Building (Table 3.5.2.5, item number 10 on page 3.5-74). Refer to the TVA response to RAI 3.3-2 (TVA letter to NRC dated September 30, 2004).
The staff found the response to RAI 3.5-11 provided in SER Section 3.3 acceptable; therefore, the staff's concern expressed in RAI 3.5-11 is resolved.
The staff also reviewed the information provided in LRA Section 3.5.2.1.5 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the diesel generator buildings' components that are not addressed by the GALL Report. The staff found the applicant's AMR results for diesel generator
 
buildings' components acceptable.
3.5.2.3.6  Standby Gas Treatment Building - Summary of Aging Management Evaluation -
Table 3.5.2.6 The staff reviewed LRA Table 3.5.2.6, which summarizes the results of AMR evaluations for the standby gas treatment building component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.6 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the standby gas treatment building components that are not
 
addressed by the GALL Report. The staff found the applicant's AMR results for the standby gas
 
treatment building components acceptable.
3-326 3.5.2.3.7  Off-Gas Treatment Building - Summary of Aging Management Evaluation -
Table 3.5.2.7 The staff reviewed LRA Table 3.5.2.7, which summarizes the results of AMR evaluations for the off-gas treatment building component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.7 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the off-gas treatment building components that are not
 
addressed by the GALL Report. The staff found the applicant's AMR results for the off-gas
 
treatment building components acceptable.
3.5.2.3.8  Vacuum Pipe Building - Summary of Aging Management Evaluation - Table 3.5.2.8
 
The staff reviewed LRA Table 3.5.2.8, which summarizes the results of AMR evaluations for the vacuum pipe building component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.8 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the vacuum pipe building components that are not addressed by
 
the GALL Report. The staff found the applicant's AMR results for the vacuum pipe building
 
components acceptable.
3.5.2.3.9  Residual Heat Removal Service Water Tunnels - Summary of Aging Management Evaluation - Table 3.5.2.9 The staff reviewed LRA Table 3.5.2.9, which summarizes the results of AMR evaluations for the RHRSW tunnels' component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.9 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the RHRSW tunnel components that are not addressed by the
 
GALL Report. The staff found the applicant's AMR results for the RHRSW tunnel components
 
acceptable.
3.5.2.3.10  Electrical Cable Tunnel from Intake Pumping Station to the Powerhouse - Summary of Aging Management Evaluation - Table 3.5.2.10 The staff reviewed LRA Table 3.5.2.10, which summarizes the results of AMR evaluations for the electrical cable tunnel from intake pumping station to the powerhouse component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.10 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the electrical cable tunnel from the intake pumping station to the
 
powerhouse components that are not addressed by the GALL Report. The staff found the
 
applicant's AMR results for the electrical cable tunnel from the intake pumping station to the
 
powerhouse components acceptable.
3-327 3.5.2.3.11  Underground Concrete Encased Structures - Summary of Aging Management Evaluation - Table 3.5.2.11 The staff reviewed LRA Table 3.5.2.11, which summarizes the results of AMR evaluations for the underground concrete-encased structures component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.11 and determined that the applicant had adequately identified applicable aging effects and the AMPs credited for
 
managing the aging effects for the underground concrete-encased structures components that
 
are not addressed by the GALL Report. The staff found the applicant's AMR results for the
 
underground concrete encased structures' components acceptable.
3.5.2.3.12  Intake Pumping Station - Summary of Aging Management Evaluation -
Table 3.5.2.12 The staff reviewed LRA Table 3.5.2.12, which summarizes the results of AMR evaluations for the intake pumping station component groups.
In LRA Table 3.5.2.12, the applicant stated that no aging management is required for submerged reinforced concrete. Plant-specific Note 5 states that for cracking, loss of bond, loss
 
of material (spalling, scaling) due to corrosion of embedded steel in concrete for inaccessible
 
areas, no plant-specific aging management is required. Plant-specific Note 6 states that, for
 
increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to
 
aggressive chemical attack of concrete for inaccessible areas, no plant-specific aging
 
management is required.
During the onsite audit, the staff reviewed other selected items in LRA Table 3.5.2.12, for MEAP combinations that are not consistent with the GALL Report. The staff requested clarifications for
 
the following material/environment combinations and the corresponding LRA Table 2 items:
Reinforced Concrete in a Submerged Environment - In LRA Table 3.5.2.12 (Intake Pumping Station - Summary of Aging Management Evaluation), rows 37 and 38, the applicant stated that
 
no aging management is required for submerged reinforced concrete. Note 5 for row 37 states
 
that for cracking, loss of bond, loss of material (spalling, scaling) due to corrosion of embedded
 
steel in concrete for inaccessible areas, no plant-specific aging management is required. Note 6
 
for row 38 states that for increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack of concrete for inaccessible areas, no
 
plant-specific aging is required.
The staff noted that a submerged component is not necessarily inaccessible. If the submerged component is accessible, it is expected that the component will be managed by the Inspection of Water Control Structures Program. The staff requested that the applicant identify all the
 
submerged concrete components in the intake pumping station, and provide the technical basis
 
for designating these components as being inaccessible. The staff also requested that the
 
applicant identify all the submerged concrete structures that will be inspected under Water
 
Control Structures Program, and describe the implementing details of the inspection of
 
submerged structures included in the Water Control Structures Program.
3-328 By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that: Browns Ferry groundwater water and Wheeler Reservoir water sample measurements presented in the response to question 297 have confirmed that parameters are well
 
below threshold limits that could cause concrete degradation (an aggressive
 
environment does not exist). It is not credible to postulate that some environmental event will occur in the future that would affect the quality of groundwater in the vicinity of
 
Browns Ferry. A change in the environment due to a chemical release would be
 
considered as an "abnormal event". NUREG-1800, "Standard Review Plan for the
 
Review of License Renewal Applications for Nuclear Power Plants," states that aging
 
effects from abnormal events need not be postulated specifically for license renewal.
In-scope submerged concrete exposed to Wheeler Reservoir water is not readily accessible for inspection. Several in-scope submerged concrete common areas outside
 
of individual pump bays where continuous flow make diver entry unsafe would require a
 
multiple unit outage to inspect. Browns Ferry will perform a one time inspection of the
 
in-scope submerged concrete in one individual pump bay to confirm the absence of
 
aggressive environmental aging effects and that a loss of intended function has not
 
occurred due to aggressive environment aging effects.
Browns Ferry will also continue to perform periodic inspections of accessible concrete in an inside air environment and outside air environment for in-scope structures with the
 
Structures Monitoring Program.
The staff concluded that the applicant's AMR is not consistent with the GALL Report and is not acceptable, because there is no commitment to conduct periodic inspection of accessible, submerged water control concrete structures. This issue was addressed in RAI 3.5-16 and is
 
discussed below.
In RAI 3.5-16, dated March 11, 2005, the staff requested the applicant to demonstrate that the groundwater is not an aggressive environment, although the facts show that an aggressive
 
environment does not exist for groundwater, and continuous water flow in several in-scope
 
submerged concrete common areas outside of individual pump bays makes diver entry unsafe.
 
Therefore, the staff requested that the applicant provide the following additional information and
 
a plant-specific commitment, as needed, in order to expedite staff closure of the issue raised by
 
the audit team:  (1)A discussion of past inspection findings, and repairs and maintenance experience for submerged, reinforced concrete structures (e.g., intake structure).  (2)A discussion of the pertinent submerged, reinforced concrete test data (as available) which demonstrate that the conditions stated in the discussion columns of items III
 
A6.1-b and III A6.1-d in GALL Report, Volume II, are fully met.    (3)A detailed description of the one-time inspection by the applicant, cited above, of the in-scope submerged concrete in one individual pump bay, including method of
 
inspection; concrete elements and parameters or types of degradation to be inspected;
 
criteria for judging the observed types, extent, and severity of reinforced concrete
 
degradation that would trigger BFN's commitment to an AMP for submerged concrete 3-329 with a periodic inspection provision, inspection frequency, and schedule for implementing the One-Time Inspection Program.    (4)A discussion of the methods (e.g., regular monitoring of the raw water for pH, chloride concentration, sulfate concentration, abrasive particulates, detrimental organic agents)
 
that will be employed to ensure that the raw se rvice water in close proximity to the intake structure remains non-aggressive to the submerged concrete during the extended period
 
of operation.
In its response, by letter dated April 5, 2005, the applicant stated:  (1)BFN's submerged concrete operating experience:
A baseline inspection for the BFN Structures Monitoring Program was established in 1997 and included the Intake Pumping Station and Gate Structure
 
No. 3. Baseline inspections and subsequent BFN Structures Monitoring Program
 
inspections included accessible interior and exterior concrete surfaces of the
 
Intake Pumping Station and Gate Structure No. 3. Only the Intake Pumping
 
Station has submerged concrete that is in the scope of license renewal. Although
 
the Intake Pumping Station submerged concrete was not inspected, there is
 
reasonable assurance that the submerged concrete results would be consistent
 
due to a lack of an aggressive environment and use of the same concrete
 
specifications for the construction as the accessible portions of the Intake
 
Pumping Station.
Defect evaluations performed since the baseline inspection and subsequent inspections are documented in the 2002 Structures Monitoring Program results.
 
Below is a highlight of plant-specific operating experience for concrete elements
 
at the Intake Pumping Station and Gate Structure No. 3. None of the identified
 
indications were considered significant or affected the function of the structure.
* Intake Pumping Station: Very minor concrete surface cracks
* Gate Structure No. 3: Very minor concrete surface cracks and spalling
 
Additionally, to capture plant operating experience for these structures, work orders (WOs), the site Correction Action Program and site Licensing Event
 
Reports (LERs) were reviewed for various operating periods:
* Work Orders between 1991 and 2004 were reviewed to determine if any corrective maintenance or repairs were performed on the Intake Pumping
 
Station (IPS). A total of 2633 WOs were reviewed for that period and no
 
work activities were found involving the submerged concrete for this
 
structure.
* The site's Correction Action Program was reviewed for the IPS to identify any adverse conditions of the structure, with emphasis on the submerged
 
concrete. A total of 1790 reports were reviewed for a time period between
 
1994 and 2004, with none being identified for the IPS submerged
 
concrete.
* Licensing Event Reports were reviewed for a period between 1985 and 2004 and none were identified affecting the IPS.
3-330  (2)GALL conditions for III A6.1-b (increase in porosity and permeability, loss of strength due to leaching of calcium hydroxide)& III A6.1-d (cracking, loss of bond, loss of material (spalling, scaling) due to corrosion of embedded steel):
See further evaluations in LRA Section 3.5.2.2.2.1, item 2 and LRA Section 3.5.2.2.2.2 for discussion on these issues.  (3)Submerged concrete one-time inspection:
The following elements apply to the one-time inspection for submerged concrete:
a.Scope of One-Time Inspection:
In-scope submerged concrete in one individual pump bay of the Intake Pumping Station. The submerged concrete surfaces will be inspected. b.Preventative Measures:
The one-time inspection specifies no preventive actions. c.Parameters Monitored or Inspected:
The following concrete aging effects will be inspected during the one-time inspection of submerged concrete at the intake pumping station (IPS).
Increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide Expansion and cracking due to reaction with aggregates Cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel Increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack The Intake Pumping Station will be periodically inspected for loss of material (spalling, scaling)and cracking due to the effects of freeze-thaw
 
at the waterline where icing conditions could occur(see GALL audit
 
question 368). The periodic inspection for aging effects due to freeze
 
thaw will be included in the BFN Structures Monitoring Program. d.Detection of Aging Effects:
Visual inspections of structural conditions will be used as the method used to detect aging effects. An inspection checklist consistent with those
 
used for Structures Monitoring Program will be used. All defects will be
 
required to be identified and documented on the inspection checklists for
 
review and evaluation by the Responsible Engineer (BFN Structures
 
Monitoring Program Engineer). Individuals trained and experienced with
 
the BFN Structures Monitoring Program will perform the inspections. e.Monitoring and Trending:
The submerged concrete at the Intake Pumping Station will be inspected prior to the extended period of operation.
3-331  f.The acceptance criteria of the BFN Structures Monitoring Program will be used. BFN Structures Monitoring Program acceptance criteria are based
 
upon Responsible Engineer (BFN Structures Monitoring Program
 
Engineer) review and classification of the results as acceptable, acceptable with deficiencies, and unacceptable respectively. These
 
performance criteria ensure that the structure:
remains capable of meeting its design basis and performing its intended function; and will not result in a loss of intended function due to a degraded condition or aging effect.
If the submerged concrete fails to meet the acceptance criteria, a cause determination evaluation will be performed. If acceptance criteria are not
 
meet, two additional pump bays will be inspected prior to the extended
 
period of operation. If one or more of the additional pump bays fails to
 
meet its acceptance criteria, then submerged concrete at the intake pump
 
station will be inspected periodically consistent with the Structures
 
Monitoring Program requirements.  (4) Periodic monitoring of raw service water:
Prior to entering the period of extended operation, BFN will initiate periodic monitoring of the raw service water in close proximity to the Intake Pumping
 
Station for the requirements of an aggressive environment as described in
 
NUREG-1557. Periodic monitoring will be consistent with the BFN Structures
 
Monitoring Program inspection frequency.
The staff reviewed the above response and found that the applicant fully had responded to RAI 3.5-16 with reasonable plant operation-based justifications. Therefore, the staff's concern
 
described in RAI 3.5-16 is resolved.
Aluminum in an Outside Air Environment
- The staff requested the applicant to provide the technical basis for concluding that no aging management of aluminum components is required for an outside environment.
The following list identifies aluminum components in an outside air environment:
* electrical and I&C penetrations
* conduits and supports
* non-ASME equivalent supports By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that aluminum alloys containing zinc are susceptible to corrosion in wetted, aggressive
 
environments. The outside air environment does not have contaminants that would cause an aggressive environment. Additionally, rain would per iodically wash any contaminant(s) from the material. The aluminum penetration sleeves and conduit at BFN are also constructed of
 
6063-T42 alloy material that is resistant to pitting, crevice corrosion, and SCC (Metals
 
Handbook, Ninth Edition, Volume 13, "Corrosion," ASM International, 1987). Therefore, the 3-332 potential for concentration of contaminates is not significant for aluminum components in an outside air environment and loss of function due to corrosion is not considered plausible.
The applicant also stated that EPRI structural tools document, "Aging Effects for Structures and Structural Components (Structural Tools)," EPRI 1002950 revision 1, August 2003, states that
 
aging management is not required for structur al aluminum and aluminum alloys in a non-aggressive ambient outside environment (gener al, galvanic, crevice and pitting corrosion, and SCC).The applicant further stated that a review of BFN operating history did not reveal any loss of intended function due to aging effects for the following aluminum components:
* electrical and I&C penetrations
* conduits and supports
* non-ASME equivalent supports The staff accepts the applicant's AMR results, that aging management is not required for these aluminum components in an outside environment, on the basis that (1) the material used is
 
resistant to corrosion and SCC, and (2) concentration of contaminates in a non-aggressive
 
ambient outside environment is not plausible The staff also reviewed the information provided in LRA Section 3.5.2.1
.12 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects, for the intake pumping station components that are not addressed
 
by the GALL Report. The staff found the applicant's AMR results for the intake pumping station
 
components acceptable.
3.5.2.3.13  Gate Structure No. 3 - Summary of Aging Management Evaluation - Table 3.5.2.13
 
The staff reviewed LRA Table 3.5.2.13, which summarizes the results of AMR evaluations for the gate structure No. 3 component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.13 and determined that the applicant had adequately identified applicable aging effects and the AMPs credited for
 
managing the aging effects for the gate structure No. 3 components that are not addressed by
 
the GALL Report. The staff found the applicant's AMR results for the gate structure No. 3
 
components acceptable.
3.5.2.3.14  Intake Channel - Summary of Aging Management Evaluation - Table 3.5.2.14
 
The staff reviewed LRA Table 3.5.2.14, which summarizes the results of AMR evaluations for the intake channel component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.14 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the intake channel components that are not addressed by the
 
GALL Report. The staff found the applicant's AMR results for the intake channel components
 
acceptable.
3-333 3.5.2.3.15  North Bank of Cool Water Channel East of Gate Structure No. 2 - Summary of Aging Management Evaluation - Table 3.5.2.15 The staff reviewed LRA Table 3.5.2.15, which summarizes the results of AMR evaluations for the north bank of cool water channel east of gate structure No. 2 component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.15 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the north bank of cool water channel east of gate structure No. 2
 
components that are not addressed by the GALL Report. The staff found the applicant's AMR
 
results for the north bank of cool water channel east of gate structure No. 2 components
 
acceptable.
3.5.2.3.16  South Dike of Cool Water Channel Between Gate Structure Nos. 2 and 3 -
Summary of Aging Management Evaluation - Table 3.5.2.16 The staff reviewed LRA Table 3.5.2.16, which summarizes the results of AMR evaluations for the south dike of cool water channel between gate structure Nos. 2 and 3 component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.16 and determined that the applicant had adequately identified applicable aging effects and the AMPs credited for
 
managing the aging effects for the south dike of the cool water channel between gate structure
 
Nos. 2 and 3 components that are not addressed by the GALL Report. The staff found the
 
applicant's AMR results for the south dike of the cool water channel between gate structure
 
Nos. 2 and 3 components acceptable.
3.5.2.3.17  Condensate Water Storage Tanks' Foundations and Trenches - Summary of Aging Management Evaluation - Table 3.5.2.17 The staff reviewed LRA Table 3.5.2.17, which summarizes the results of AMR evaluations for the condensate water storage tanks' foundations and trenches component groups.
During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.17, for MEAP combinations that are not consistent with the GALL Report. The staff requested clarifications for
 
the following material/environment combinations and the corresponding LRA Table 2 item:
Earthfill & Rock in a Buried Environment - This item indicates that the equipment supports and foundations are earth fill (rock and sand). The staff requested that the applicant explain the
 
technical bases for concluding that there are no aging effects requiring management.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the foundation for the CWST is comprised of a concrete ring foundation with the interior
 
portion of the ring foundation filled with crushed rock and sand. The earthen materials (rock and
 
sand) of the CWST foundation interior base are protected from environmental weathering
 
conditions by the concrete perimeter ring and CWST tank bottom. There are no aging effects for
 
the earthen materials of the CWST foundation interior base that require aging management.
 
Aging management of the CWST concrete foundation ring is managed by the Structures
 
Monitoring Program. Aging management of t he CWST bottom will be performed by the One-Time Inspection Program.
3-334 The applicant also stated that a review of BFN operating history did not reveal any loss of intended function due to aging effects for earthen materials of the CWST foundation interior
 
base. Based on the additional information provided by the applicant, the staff concurs with the applicant's AMR results for the crushed rock and sand base of the CWST. The staff concluded
 
that aging management is not required because these materials are adequately protected by
 
the concrete perimeter ring and the CWST tank bottom.
The staff also reviewed the information provided in LRA Section 3.5.2.1.17 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the condensate water storage tanks' foundations and trenches
 
components that are not addressed by the GALL Report. The staff found the applicant's AMR
 
results for the condensate water storage tanks' foundations and trenches components
 
acceptable.
3.5.2.3.18  Containment Atmosphere Dilution Storage Tanks' Foundations - Summary of Aging Management Evaluation - Table 3.5.2.18 The staff reviewed LRA Table 3.5.2.18, which summarizes the results of AMR evaluations for the containment atmosphere dilution storage tanks' foundations component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.18 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the containment atmosphere dilution storage tanks' foundations
 
components that are not addressed by the GALL Report. The staff found the applicant's AMR
 
results for the containment atmosphere dilution storage tanks' foundations components
 
acceptable.
3.5.2.3.19  Reinforced Concrete Chimney
- Summary of Aging Management Evaluation -
Table 3.5.2.19 The staff reviewed LRA Table 3.5.2.19, which summarizes the results of AMR evaluations for the reinforced concrete chimney component groups.
During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.19 for MEAP combinations that are not consistent with the GALL Report. The staff requested clarifications for
 
the following material/environment combinations and the corresponding LRA Table 2 items:
Carbon Steel in a Buried Environment- The applicant stated that the Structures Monitoring Program relies on visual inspections whenever the components are uncovered during station yard area excavations. The staff requested that the applicant confirm that this applies to buried
 
mechanical penetrations, clarify what other components are included in this provision, and
 
explain whether this is an enhancement to the ex isting program or whether this provision is covered in the current program.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that LCEI-CI-C9 will be enhanced to include inspection of mechanical penetrations when
 
accessible. There are no other buried carbon steel components included with the program; 3-335 however, LCEI-CI-C9 will also be enhanced to include the inspection of buried concrete whenaccessible. With enhancements, LCEI-CI-C9 will be consistent with GALL AMP XI.S6.
The applicant also stated that the Buried Piping and Tanks Inspections Program provides the inspection requirements of buried piping when accessible. The Buried Piping and Tanks Inspections Program is consistent with GALL AMP XI.M34. Section 7.2.9.2 of LCEI-CI-C9
 
currently provides the inspection attributes of buried piping, which includes pipe connections
 
and joints, and is credited as the Buried Piping and Tanks Inspections Program.
The staff concluded that the applicant's commitment to enhance the Structures Monitoring Program to include inspection of buried mechanical penetrations when accessible, provides a
 
level of aging management for buried mechanical penetrations that is comparable to the GALL
 
Report recommendations for buried concrete, piping and tanks. Therefore, the staff found this
 
acceptable.
The staff also reviewed the information provided in LRA Section 3.5.2.1.19 and determined that the applicant had adequately identified applicable aging effects and the AMPs credited for
 
managing the aging effects for the reinforced concrete chimney components that are not
 
addressed by the GALL Report. The staff found the applicant's AMR results for the reinforced
 
concrete chimney components acceptable.
3.5.2.3.20  Turbine Buildings - Summary of Aging Management Evaluation - Table 3.5.2.20
 
The staff reviewed LRA Table 3.5.2.20, which summarizes the results of AMR evaluations for the turbine buildings component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.20 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects, for the turbine buildings components that are not addressed by the
 
GALL Report. The staff found the applicant's AMR results for the turbine buildings components
 
acceptable.
3.5.2.3.21  Diesel High Pressure Fire Pump House - Summary of Aging Management Evaluation - Table 3.5.2.21 The staff reviewed LRA Table 3.5.2.21, which summarizes the results of AMR evaluations for the diesel high-pressure fire pump house component groups.
During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.21 for MEAP combinations that are not consistent with the GALL Report. The staff requested clarifications for
 
the following material/environment combinations and the corresponding LRA Table 2 item:
Stainless Steel in a Submerged Environment - This item credits the Structures Monitoring Program for managing the effects of loss of material due to crevice corrosion and pitting
 
corrosion for stainless steel beams, columns, plates, and trusses in a submerged environment.
 
The staff requested the applicant to identify (1) the components included in this item and (2)
 
where they are located, and (3) the submer ged environment. A description of the types of inspections that will be performed under the Structures Monitoring Program for these
 
components and clarification on whether these inspections are included in the current scope of 3-336 the Structures Monitoring Program was also requested. The staff also requested the applicant to provide the technical basis for not monitoring water chemistry.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that LRA Table 3.5.2.21 row 28 applies to submerged portions of the stainless steel debris
 
screen under the diesel high pressure fire pump house. The intended functions of the debris
 
screen are debris protection and NSR structural support. The applicant also stated that the
 
miscellaneous components portion of the Structures Monitoring Program will be enhanced to
 
visually inspect the submerged portions of the debris screen for loss of material due to crevice
 
and pitting corrosion. The applicant noted that portions of the diesel high-pressure fire pump
 
house debris screen are submerged in a raw water environment; therefore, monitoring of water
 
chemistry is not applicable as an AMP.
The staff accepts the applicant's commitment to enhance the Structures Monitoring Program to visually inspect the submerged portions of the stainless steel debris screen for loss of material
 
due to crevice and pitting corrosion. The staff considered this to be analogous to submerged
 
portions of water control structures for which visual inspection conducted as part of the
 
Structures Monitoring Program has been previously accepted.
The staff also reviewed the information provided in LRA Section 3.5.2.1.21 and determined that the applicant had adequately identified applicable aging effects and the AMPs credited for
 
managing the aging effects for the diesel high-pressure fire pump house components that are
 
not addressed by the GALL Report. The staff found the applicant's AMR results for the diesel
 
high-pressure fire pump house components acceptable.
3.5.2.3.22  Vent Vaults - Summary of Aging Management Evaluation - Table 3.5.2.22
 
The staff reviewed LRA Table 3.5.2.22, which summarizes the results of AMR evaluations for the vent vaults component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.22 and determined that the applicant had adequately identified applicable aging effects and the AMPs credited for
 
managing the aging effects for the vent vaults components that are not addressed by the GALL Report. The staff found the applicant's AMR results for the vent vaults components acceptable.
3.5.2.3.23  Transformer Yard - Summary of Aging Management Evaluation - Table 3.5.2.23
 
The staff reviewed LRA Table 3.5.2.23, which summarizes the results of AMR evaluations for the transformer yard component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.23 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the transformer yard components that are not addressed by the
 
GALL Report. The staff found the applicant's AMR results for the transformer yard components
 
acceptable.
3-337 3.5.2.3.24  161 kV Switchyard - Summary of Aging Management Evaluation - Table 3.5.2.24 The staff reviewed LRA Table 3.5.2.24, which summarizes the results of AMR evaluations for the 161 kV switchyard component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.24 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the 161 kV switchyard components that are not addressed by the
 
GALL Report. The staff found the applicant's AMR results for the 161 kV switchyard
 
components acceptable.
3.5.2.3.25  500 kV Switchyard - Summary of Aging Management Evaluation - Table 3.5.2.25
 
The staff reviewed LRA Table 3.5.2.25, which summarizes the results of AMR evaluations for the 500 kV Switchyard component groups.
The staff also reviewed the information provided in LRA Section 3.5.2.1.25 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the 500 kV switchyard components that are not addressed by the
 
GALL Report. The staff found the applicant's AMR results for the 500 kV switchyard
 
components acceptable.
3.5.2.3.26  Structures and Component Supports - Summary of Aging Management Evaluation -
Table 3.5.2.26 The staff reviewed LRA Table 3.5.2.26, which summarizes the results of AMR evaluations for the structures and component supports component groups.
During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.26 for MEAP combinations that are not consistent with the GALL Report. The staff requested clarifications for
 
the following material/environment combinations and the corresponding LRA Table 2 items:
Aluminum in an Inside Air Environment - The staff requested the applicant to provide the technical basis for concluding that no aging management of aluminum supports is required for
 
loss of mechanical function in an inside air environment.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that aluminum in an inside air environment applie s to aluminum pipe lugs for equivalent ASME Class 2 or 3 piping in the reactor buildings (ins ide air environment). Aluminum external surfaces are not susceptible to corrosion unless their surfaces are wetted and there is a potential for
 
concentration of contaminants. The aluminum pipe lugs in the reactor building are not exposed
 
to a wetted aggressive/corrosive environment. Therefore, the potential for concentration of
 
contaminants is not significant for aluminum components in an inside air environment and loss of mechanical function due to corrosion is not considered plausible.
The applicant further stated that EPRI structural tools document, "Aging Effects for Structures and Structural Components (Structural Tools)" EPRI 1002950 Revision 1, August 2003, states
 
that aging management is not required for structur al aluminum and aluminum alloys in an inside environment (general, galvanic, crevice, pitting corrosion, and SCC).
3-338 The applicant also stated that a review of BFN operating history did not reveal any loss of intended function due to aging effects for aluminum pipe lugs for equivalent ASME Code
 
Class 2 or 3 piping in the reactor buildings for an inside air environment.
The staff found that the applicant had not considered loss of mechanical function due to aging mechanisms other than corrosion. This omission is not consistent with the GALL Report. The
 
applicant also failed to credit an existing AMP (IWF) that includes the subject components in its
 
scope.The staff requested additional information to resolve this issue, and related issues. The
 
disposition is discussed at the end of this section, as part of the review of LRA Table 3.5.2.26
 
AMRs.The staff also reviewed the information provided in LRA Section 3.5.2.1.26 and determined that the applicant had adequately identified applicable aging effects, and the AMPs credited for
 
managing the aging effects for the structures and component supports commodities
 
components that are not addressed by the GALL Report. The staff found the applicant's AMR
 
results for the structures and component supports commodities components acceptable.
Aluminum in an Outside Air Environment
- The staff requested the applicant to provide the technical basis for concluding that no aging management of aluminum components is required for an outside environment.
The following list identifies aluminum components in an outside air environment:
* electrical and I&C penetrations
* conduits and supports
* non-ASME equivalent supports By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that aluminum alloys containing zinc are susceptible to corrosion in wetted aggressive
 
environments. The outside air environment does not have contaminants that would cause an aggressive environment. Additionally, rain would per iodically wash any contaminant(s) from the material. The aluminum penetration sleeves and conduit at BFN are also constructed of
 
6063-T42 alloy material that is resistant to pitting, crevice corrosion, and SCC (Metals
 
Handbook, Ninth Edition, Volume 13, "Corrosion," ASM International, 1987). Therefore, the
 
potential for concentration of contaminates is not significant for aluminum components in an
 
outside air environment and loss of function due to corrosion is not considered plausible.
The applicant also stated that EPRI structural tools document, "Aging Effects for Structures and Structural Components (Structural Tools)" EPRI 1002950 Revision 1, August 2003, states that
 
aging management is not required for structur al aluminum and aluminum alloys in a non-aggressive ambient outside environment (gener al, galvanic, crevice and pitting corrosion, and SCC).The applicant further stated that a review of Browns Ferry operating history did not reveal any loss of intended function due to aging effects for the following aluminum components:
* electrical and I&C penetrations
* conduits and supports 3-339
* non-ASME equivalent supports The staff accepts the applicant's AMR results, that aging management is not required for these aluminum components in an outside environment, on the basis that (1) the material used is
 
resistant to corrosion and SCC, and (2) concentration of contaminates in a non-aggressive
 
ambient outside environment is not plausible Carbon Steel in a Containment Air Environment
- For the high-strength bolts included under this item, the staff requested that the applicant describe the bolting material, the nominal and
 
as-built yield strengths, and the hardness of the material. The applicant was also requested to
 
discuss the disposition of the recommendations for a comprehensive Bolting Integrity Program, as delineated in NUREG-1339, and industry recommendations, as delineated in EPRI NP-5769.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating:
The only high strength structural bolting (ultimate tensile strength [UTS] > 150 ksi)
 
material specified for use at BFN is ASTM A-490 (Ref. General Engineering
 
Specification G-29BS01, PS 4.M.4.4, "ASME Section III and Non-ASME Section III (including AISC, ANSI B31.1, and ANSI B31.5) Bolting Material"). The ultimate tensile
 
strength for A-490 bolting 1/2" to 1 1/2" may vary between 150 to 170 ksi, a minimum yield
 
strength of 130 ksi is specified and hardness may vary from 33 to 38 Rockwell C (ASTM
 
A-490 Standard).
The Bolting Integrity Program manages loss of material of mechanical component steelbolting within the scope of License Renewal. ASME Section XI manages aging of
 
structural bolting (encompassed by 'Support members; welds; bolted connections;
 
support anchorage to building structure') for ASME equivalent supports. Structures
 
Monitoring Program manages aging of structural bolting for the remaining structural
 
supports within the scope of License Renewal. The support components, including the
 
bolting, are periodically inspected for loss of material by these programs.
High strength bolting (UTS >150 ksi) is not considered susceptible to cracking due to stress corrosion cracking at BFN. For SCC to manifest in high strength bolting, an
 
aggressive chemical or wetted environment is required in addition to susceptible material
 
and high tensile stresses. High strength bolting (UTS >150 ksi) used in ASME equivalent
 
supports at BFN are installed in indoor air environments that are not exposed to
 
aggressive chemicals, periodic wetting, or splash zones. Additionally, high strength
 
bolting is used for Unit 1 drywell floor steel framing and other structural purposes to
 
connect the RPV skirt flange to the top flange of the ring girder in the drywell and these
 
bolts are exposed to a containment atmosphere environment in the drywell not subject to
 
aggressive chemicals, periodic wetting or splash zones. As noted below, thread
 
lubricants are also controlled to eliminate corrosive environmental effects. Therefore an
 
aggressive chemical or wetted environment does not exist.
Per the EPRI Mechanical and Structural Tools and EPRI NP-5769, high strength bolting is considered susceptible to SCC in a corrosive environment with the use of thread
 
lubricants containing molybdenum disulfide. Approved thread lubricants for use in bolted
 
joints at BFN are specified in General Engineering Specification (GES) G-29B-S01 PS
 
4.M.1.1 and Section 3.9.2 notes that lubricants containing molybdenum disulfide shall
 
not be used.
3-340 Structural bolting procurement activities, receipt inspection and installation (torquing), as defined in TVA procedure GES G-29B-S01, P.S.4.M.4.4, 'ASME Section III and Non-
 
Section III (Including AISC, ANSI B31.1, and ANSI B31.5) Bolting Material', are
 
considered part of TVA's Bolting Integrity Program and meet the industry
 
recommendations for these activities as delineated in NUREG-1339 and EPRI NP-5769.
The staff found that the applicant had presented a sufficient technical basis to support its AMR results that high-strength bolting used in structural applications is not susceptible to SCC. The
 
staff determined that meeting the recommendations delineated in NUREG-1339 and EPRI
 
NP-5769 provides reasonable assurance that SCC will not occur.
Carbon Steel in an Inside Air Environment - The applicant indicated that only loss of material due to general corrosion and loss of mechanical function due to corrosion are considered
 
applicable aging effects for the subject ASME-equivalent supports. The staff requested the
 
applicant to provide the technical basis for concluding that other aging mechanisms are not
 
applicable.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that Table 3.5.2.26 row 2 applies to ASME-equivalent Class 1 supports. The AMR for the
 
material and environment combination of carbon steel in an inside air environment was
 
performed and the applicant concluded that the only plausible aging mechanisms needing
 
managing were:
* loss of material due to general corrosion
* loss of mechanical function due to corrosion, distortion, dirt, overload, and fatigue due to vibratory and cyclic thermal loads The applicant further stated that ASME Section XI, Subsection IWF will be used to manage these aging effects of loss of material and loss of mechanical function identified in
 
Table 3.5.2.26 row 2. The staff found this acceptable, because it is consistent with GALL.
Carbon Steel in an Outside Air Environment
- The applicant indicated that only loss of material due to general corrosion, crevice corrosion, and pitting corrosion are considered applicable
 
aging effects for the subject ASME-equivalent supports. The staff requested the applicant to
 
provide the technical basis for concluding that other aging mechanisms are not applicable.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that Table 3.5.2.26, row 9 applies to ASME-equivalent Class 2 and 3 supports. The AMR for the
 
material/environment combination of carbon steel in an outside air environment was performed
 
and the applicant concluded that the only plausible aging mechanism that needed to be
 
managed was loss of material due to general, crevice, and pitting corrosion. The applicant further stated that the ASME Code Section XI, Subsection IWF will be used to manage the aging effect of loss of material identified in Table 3.5.2.26, row 9.
The staff noted that loss of mechanical function is also managed by IWF, even though the applicant did not identify this aging effect. The staff accepts the applicant's AMR results solely 3-341 on the basis that IWF is credited for license renewal, and IWF will manage loss of mechanical function in addition to loss of material.
The applicant also stated that the referenced table row applies to ASME-equivalent Class 2 and 3 supports and is not applicable to Class MC supports, and that the response to RAI-3.5-6 will
 
address the AMR results for Class MC supports.
Carbon Steel in a Submerged Environment
- The staff requested that the applicant identify (1) the components included in this item, (2) where they are located, and (3) the submerged
 
environment. The staff also requested the applicant to provide the technical basis for not
 
including these component types in the One-Time Inspection Program to confirm the
 
effectiveness of the Chemistry Control Program.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that Table 3.5.2.26, row 57 applies to carbon steel non-ASME Code equivalent supports inside
 
the CWST. Aging of carbon steel supports submerged in the CWST (treated water environment)
 
will be managed through monitoring CWST water chem istry by the Chemistry Control Program.
Effectiveness of the CWST Chemistry Contro l Program will be confirmed by the One-Time Inspection Program of carbon steel mechanical components in a treated water (condensate
 
water) environment as noted in LRA Table 3.4.2.2 (Condensate and Demineralized Water
 
System). The staff found the use of the Chemistry Control Program and confirmation by the One-Time Inspection Program acceptable to manage aging of submerged supports inside the condensate
 
water storage tank, on the basis that the supports are treated as part of the tank in the applicant's AMR.
Lubrite in an Inside Air Environment - The staff requested that the applicant describe where the referenced items are used and provide the technical basis for concluding that no aging
 
management of the lubrite plates used in BFN is required in an inside air environment.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that Table 3.5.2.26, row 35 applies to the lubrite plates used for the core spray and RHR
 
pump/equipment base supports. EPRI 1002950, "Aging Effects for Structures and Structural
 
Components (Structural Tools), Revision 1," August 2003, states that lubrite material resists
 
deformation, has a low coefficient of friction, resists softening at elevated temperatures, absorbs
 
grit and abrasive particles, is not susceptible to corrosion, withstands high intensities of
 
radiation, and will not score or mar. Lubrite products are solid, permanent, completely self
 
lubricating, and require no maintenance. The reactor building environment at the location of the
 
core spray and RHR pump equipment base supports is not an aggressive or wetted
 
environment.
The applicant also stated that a search of BFN and industry operating experience did not identify any instances of lubrite plate degradation or failure to perform its intended function due
 
to aging effects. NUREG-1759, "Safety Evaluation Report Related to the License Renewal of
 
Turkey Point Nuclear Plant, Units 3 and 4," and NUREG-1769, "Safety Evaluation Report
 
Related to the License Renewal of Peach Bottom Atomic Power Station, Units 2 and 3," concur
 
that there are no lubrite plate aging effects that require aging management.
3-342 Based on the additional information provided by the applicant, the staff found the applicant's AMR results for lubrite plates to be acceptable. Prior staff evaluations of this issue have
 
concluded that there are no aging effects requiring aging management.
Reinforced Concrete in a Buried Environment - This item applies to buried reinforced concrete equipment supports and foundations. The staff requested that the applicant explain how the
 
Structures Monitoring Program is used to manage these buried (presumably inaccessible)
 
components.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that Table 3.5.2.26, row 41 applies to transformer pads/foundations in the transformer yard, 161kV switchyard and 500kV switchyard in a buried environment. The electrical equipment
 
concrete foundations are exposed to both the outside air environment and the inaccessible
 
buried environment. The outside air environment is addressed in LRA Table 3.5.2.26, row 44.
 
Reduction in concrete anchor capacity will manifest itself at the anchor locations which are
 
located in the outside air environment. The Structures Monitoring Program will manage reduction of concrete anchor capacity for those portions of the equipment foundations exposed
 
to the outside air environment. Aging management for below grade inaccessible concrete will be based on inspection of the accessible concrete in the outside air environment.
Based on the additional information provided by the applicant, the staff found the applicant's AMR results for the buried portions of the concrete transformer pads/foundations to be
 
acceptable. Periodic inspection of the accessible concrete by the Structures Monitoring
 
Program will provide an indication of the condition of the buried concrete.
Stainless Steel in a Submerged Environment - The staff requested the applicant to identify (1) the ASME-equivalent supports and components included in this item, (2) where they are
 
located, and (3) the submerged environment. The applicant was also requested to provide the BFN AMR for this item and discuss the technical basis for not crediting ASME Section XI, Subsection IWF as the AMP.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that LRA Table 3.5.2.26, row 11 applies to the stainless steel ASME-equivalent Class 2
 
supports for the safety-related valve (SRV) discharge lines that are in the submerged
 
environment of the suppression pool water. The Chemistry Control Program and a one-time
 
inspection will manage loss of material for stainless steel ASME-equivalent Class 2 supports
 
exposed in a submerged treated (suppression pool) water environment. These lines are exemptfrom inspection per ASME Section XI.
Based on the additional information provided by the applicant, the staff accepts the applicant's AMR results for stainless steel ASME Code equivalent Class 2 supports for the SRV discharge
 
lines that are in the submerged environment of the suppression pool water. The staff concurred
 
that these supports are exempt from IWF inspection because they are not fluid filled. The
 
credited AMPs are consistent with the GALL Report recommendations for Class 1 stainless
 
steel small-bore piping. The staff found this appropriate, in lieu of IWF.
LRA Table 3.5.2.26 - In LRA Table 3.5.2.26, rows 5, 6, 10, 14, 15, 16, and 18, the applicant indicated that no aging management is required in containment atmosphere, inside air and
 
outside air environments for stainless steel and non-ferrous aluminum ASME Code equivalent 3-343 supports and components. Note 3 to LRA Table 3.5.2.26, which applies to all of the cited row numbers, states that there are no applicable aging effects for the material/environment
 
combinations and that this is consistent with industry guidance. The applicant does not credit
 
ASME Code AMP for license renewal.
It was the staff's understanding that the support components covered by the cited row numbers are required to be inspected under IWF during the current licensing term. Therefore, the staff
 
requested that the applicant explain why this CLB commitment would not continue for the
 
extended period of operation.
By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating that these ASME-equivalent supports and components will continue to be inspected consistent with the commitments contained in the CLB for the ASME Code Section XI Subsection IWF
 
Program requirements in effect during the extended period of operation. The applicant further
 
stated that the specific reference to row numbers noted in the audit team's question all had
 
material and environmental combinations that, upon performance of the AMR, determined that
 
there were no aging effects that required managing for license renewal.
The staff noted inconsistencies between the applicant's AMR for the cited row numbers, all of which are not susceptible to general corrosion, and the applicant's AMR for carbon steel ASME
 
Code equivalent supports and components, which are susceptible to general corrosion. For the
 
cited row numbers, the applicant considers corrosion to be the only age-related mechanism
 
leading to loss of mechanical function. The applicant's position is that the other GALL Report
 
listed mechanisms leading to loss of mechanical function (distortion, dirt, overload, fatigue due
 
to vibratory and cyclic thermal loads; elastomer hardening) are not age-related. On this basis, the applicant has concluded that aging management for loss of mechanical function is not
 
applicable to the cited row numbers. However, for carbon steel ASME Code equivalent supports
 
and components, the applicant identified additional GALL Report listed mechanisms as leading
 
to loss of mechanical function (see LRA Table 3.5.2.26, rows 2, 4, 12, and 13); and credits IWF
 
as the AMP for license renewal.
The staff's review of LRA Table 3.5.2.26 identified areas in which additional information was necessary to complete the review of the applicant's results. The applicant responded to the
 
staff's RAI as discussed below.
In RAI 7.2.5-2, dated March 8, 2005, the staff requested the applicant to: (1) submit a detailed description of all supports covered by LRA Table 3.5.2.26, rows 5, 6, 10, 14, 15, 16, and 18;
 
and (2) for each support, provide the technical basis for concluding that every GALL Report
 
listed mechanism (corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic thermal
 
loads; elastomer hardening) leading to loss of mechanical function is not applicable. As an
 
alternative, the applicant may credit IWF as an AMP for license renewal.
In its response, by letter dated April 5, 2005, the applicant provided its formal response, which states: For row numbers 5, 6, 15, and 16 of Table 3.5.2.26, the table will be revised to credit IWF as the aging management program.
3-344 The supports for row number 10 are the typical pipe supports comprised of steel structural shapes, welded or bolted together and attached to the concrete
 
structure/building with base plates or attached to other steel structural shapes of the
 
building. The aging effect for GALL III.B1.2.1-a is "Loss of Material" and not "Loss of
 
Mechanical Function" as noted in the question. The AMR is consistent with the reference
 
to Note 3 of Table 3.5.2.26. Additionally, this is consistent with the proposed revision to
 
GALL for Item number III.B1.2-5 (TP-5) for this material and environment combination.
 
The AMR conclusion for the proposed GALL revision to GALL for Item number III.B1.2-5 (TP-5) is "no aging effects are applicable"; therefore, no AMP is required.
The supports in-scope for row number 14 of Table 3.5.2.26 are integral welded lugs to the process pipe. The lug material is the same as the process pipe (aluminum). Aluminum external surfaces are not susceptible to corrosion unless
 
their surfaces are wetted or exposed to an aggressive environment. Since
 
periodic wetting or exposure to aggressi ve environments of component external surfaces in an inside air environment will not occur, loss of mechanical function
 
due to corrosion is not considered plausible and the other aging mechanisms (distortion, dirt, overload, fatigue due to vibratory and cyclic thermal loads;
 
elastomer hardening) do not apply.
The supports in-scope for row number 18 of Table 3.5.2.26 are integral welded lugs to the process pipe. The lug material is the same as the process pipe (stainless steel). The in-scope piping system is located in the Residual Heat
 
Removal Service Water (RHRSW) Tunnels (LRA Section 2.4.3.5). Since the
 
piping and supports are located within the RHRSW Tunnels and are exposed to
 
an inside air environment and are not ex posed to an outside air environment as noted in the AMR table, Row 18 can be deleted. Row number 10 (applicable
 
GALL item - III.B1.2.1-a) is the applicable AMR line item for the material and
 
environment combinations of these stainless steel supports in the RHRSW
 
Tunnel. The staff reviewed the applicant's response and found it acceptable since the AMRs are consistent with the GALL Report. Therefore, the staff's concern described in RAI 7.2.5-2 is
 
resolved.In RAI 3.5-12, dated December 10, 2004, the staff stated that non-ferrous aluminum conduit and supports that are exposed to outside air are listed in LRA Table 3.5.2.26 as components having
 
no applicable AERM; thus, no AMP is designated to manage their aging. Depending on the
 
severity of the outside air environment to whic h the components are consistently exposed, some aluminum conduit and supports may experience loss of material aging effect. Therefore, the
 
staff requested that the applicant discuss its past plant-specific inspection results of these
 
supports in order to provide an operating experience-based justification for the above AMR
 
finding.In its response, by letter dated January 31, 2005, the applicant stated:
The following list identifies aluminum components in an outside air environment:
* electrical and I&C penetrations
* conduits and supports 3-345
* non-ASME equivalent supports Aluminum alloys containing zinc are susceptible to corrosion in wetted aggressive environments. However, the outside air environment does not contain contaminants that
 
would cause an aggressive environment. In addition, the aluminum conduit and conduit
 
supports are also constructed of 6063-T42 alloy that is resistant to pitting, crevice
 
corrosion, and SCC (Metals Handbook, Ninth Edition, Volume 13, "Corrosion," ASM
 
International, 1987). Since the potential for concentration of contaminates is not
 
significant, and the specific aluminum grade used in an outside air environment is more
 
resistant to corrosion, loss of function due to corrosion is not considered plausible.
A review of BFN operating history, the structures monitoring baseline inspection, and the results for the first structures monitoring inspection period did not reveal any loss of
 
intended function due to aging effects for the following aluminum components:
* electrical and I&C penetrations,
* conduits and supports
* non-ASME equivalent supports Based on the applicant's additional information provided above and operating experience that (1) the potential for concentration of contaminates at BFN site is not significant, and the specific
 
aluminum grade used in an outside air environment is more resistant to corrosion, loss of
 
function due to corrosion is not considered plausible, and (2) a review of operating history, the
 
structures monitoring baseline inspection, and the results of the first structures monitoring
 
inspection period did not reveal any loss of intended function due to aging effects for the
 
aluminum components. The staff found the AMR results for its aluminum components adequate and acceptable. Therefore, the staff's concern described in RAI 3.5-12 is resolved.
In RAI 3.5-13, dated December 10, 2005, the staff stated that LRA Table 3.5.2.26 lists equipment supports and foundations made of non-ferrous lubrite that are exposed to inside air
 
environment as components having no AERM; therefore, no AMP is designated for the
 
components. NUREG-1801, Table III.B1.1.3-a identifies loss of mechanical function, corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic thermal loads, and elastomer
 
hardening as potentially applicable aging effects for the lubrite components, and designates ASME Code Section XI, Subsection IWF Program as the AMP to manage the listed aging
 
effects. Therefore, the staff requested the applicant to discuss past plant-specific inspection and
 
maintenance results of these lubrite supports in order to provide an operating experience-based
 
justification for the LRA assessment.
In its response, by letter dated January 31, 2005, the applicant stated:
The Table 3.5.2.26 entry applies to the lubrite plates used for the Core Spray and RHR pump equipment support plates. EPRI report 1002950, "Aging Effects for Structures and
 
Structural Components (Structural Tools) Revision 1," states that lubrite material resists
 
deformation, has a low coefficient of friction, resists softening at elevated temperatures, absorbs grit and abrasive particles, is not susceptible to corrosion, withstands high
 
intensities of radiation, and will not score or mar. lubrite products are solid, permanent, completely self lubricating, and require no maintenance. The Browns Ferry reactor 3-346 building environment at the location of the Core Spray and RHR pump equipment support plates is not an aggressive or wetted environment.
A search of Browns Ferry and industry operating experience did not identify any instances of Lubrite plate degradation or failure to perform its intended function due to
 
aging effects. NUREG-1759, "Safety Evaluation Report Related to the License Renewal
 
of Turkey Point Nuclear Plant, Units 3 and 4" and NUREG-1769, "Safety Evaluation
 
Report Related to the License Renewal of Peach Bottom Atomic Power Station, Units 2
 
and 3," concur that there are no aging effects for lubrite plate that require aging
 
management.
Based on the applicant's additional information provided above that (1) the reactor building environment at the location of the core spray and RHR pump equipment support plates is not an
 
aggressive or wetted environment, (2) lubrite products are solid, permanent, completely self
 
lubricating, and require no maintenance, (3) a search of BFN and industry operating experience
 
did not identify any instances of lubrite plate degradation or failure to perform its intended
 
function due to aging effects, and (4) prior staff positions taken with respect to the aging
 
management of lubrite plate under similar env ironmental conditions, as reported in NUREGs 1759 and 1769, the staff found the applicant's response to RAI 3.5-13 acceptable. Therefore the
 
staff's concern described in RAI 3.5-13 is resolved.
Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluated AMR results involving MEAP combinations that are not evaluated in the GALL Report. The staff
 
found that the applicant demonstrated that the effects of aging will be adequately managed so
 
that the intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
Sections 3.5.2.3.27 and 3.5.2.3.28. The following AMRs were added as a result of SER Sections 2.4.3.9 and 2.4.7.7, respectively.
3.5.2.3.27  South Access Retaining Walls - Summary of Aging Management Evaluation -
Table 3.5.2.27 The staff reviewed added LRA Table 3.5.2.27, which summarizes the results of AMR evaluations for the south access retaining walls component groups.
On the basis of its review of the information provided in added LRA Section 3.5.2.1.27 and Table 3.5.2.27, the staff determined that the applicant had adequately identified applicable
 
aging effects, and the AMP credited for managing the aging effects, for the south access
 
retaining walls components that are not addressed by the GALL Report. The staff found the
 
applicant's AMR results for the south access retaining walls components acceptable.
3.5.2.3.28  Isolation Valve Pit - Summary of Aging Management Evaluation - Table 3.5.2.28
 
The staff reviewed added LRA Table 3.5.2.28, which summarizes the results of AMR evaluations for the isolation valve pit component groups.
On the basis of its review of the information provided in added LRA Section 3.5.2.1.28 and Table 3.5.2.28, the staff determined that the applicant had adequately identified applicable 3-347 aging effects, and the AMP credited for managing the aging effects, for the isolation valve pit components that are not addressed by the GALL Report. The staff found the applicant's AMR
 
results for the isolation valve pit components acceptable.
 
====3.5.3 Conclusion====
The staff concluded that the applicant provided sufficient information to demonstrate that the effects of aging of the containments, structures, and component supports components that are
 
within the scope of license renewal and subject to an AMR will be adequately managed so that
 
the intended function(s) will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
The staff also reviewed the applicable UFSAR supplement program summaries and concluded that they adequately describe the AMPs credited for managing aging of the containments, structures, and component supports, as required by 10 CFR 54.21(d).
3-348 3.6  Aging Management of Electrical and Instrumentation and Controls This section of the SER documents the staff's review of the applicant's AMR results for the electrical and I&C components and component groups.3.6.1  Summary of Technical Information in the Application In LRA Section 3.6, the applicant provided AMR results for components. In LRA Table 3.6.1,"Summary of Aging Management Evaluations for Electrical and Instrumentation and Control
 
Systems Evaluated in Chapter VI of NUREG-1801," the applicant provided a summary
 
comparison of its AMRs with the AMRs evaluated in the GALL Report for the electrical and I&C
 
components and component groups.
The applicant's AMRs incorporated applicable operating experience in the determination of AERMs. These reviews included evaluation of plant-specific and industry operating experience.
 
The plant-specific evaluation included reviews of condition reports and discussions with
 
appropriate site personnel to identify AERMs. The applicant's review of industry operating
 
experience included a review of the GALL Report and operating experience issues identified
 
since the issuance of the GALL Report.
 
====3.6.2 Staff====
Evaluation The staff reviewed LRA Section 3.6 to determine if the applicant had provided sufficient information to demonstrate that the effects of aging for the electrical and instrumentation and
 
control components that are within the scope of license renewal and subject to an AMR will be
 
adequately managed so that the intended functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff performed an onsite audit during the weeks of June 21 and July 26, 2004, of AMRs to confirm the applicant's claim that certain identified AMRs were consistent with the GALL Report.
 
The staff did not repeat its review of the matters described in the GALL Report; however, the
 
staff did verify that the material presented in the LRA was applicable and that the applicant had
 
identified the appropriate GALL AMRs. The staff's evaluations of the AMPs are documented in
 
SER Section 3.0.3. Details of the staff's audit evaluation are documented in the BFN audit and
 
review report and are summarized in SER Section 3.6.2.1.
In the onsite audit, the staff also reviewed those selected AMRs that were consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the
 
applicant's further evaluations were consistent with the acceptance criteria in SRP-LR
 
Section 3.6.2.2, dated July 2001. The staff's audit evaluations are documented in the BFN audit
 
and review report and are summarized in SER Section 3.6.2.2.
In the onsite audit, the staff also conducted a technical review of the remaining AMRs that were not consistent with, or not addressed in, the GALL Report. The audit and technical review
 
included evaluating whether all plausible aging effects were identified and evaluating whether
 
the aging effects listed were appropriate for the combination of materials and environments
 
specified. The staff's audit evaluations are documented in the BFN audit and review report and
 
are summarized in SER Section 3.6.2.3. The staff's evaluation of its technical review is also
 
documented in SER Section 3.6.2.3.
3-349 Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or
 
monitoring aging for the electrical and I&C components.
Table 3.6-1, below, provides a summary of the staff's evaluation of components, aging effects/mechanisms, and AMPs listed in LRA Section 3.6 that are addressed in the GALL
 
Report.Table 3.6-1  Staff Evaluation for Electrical and Instrumentation and Controls in the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation Electrical equipment subject to 10 CFR 50.49
 
environmental
 
qualification (EQ)
 
requirements
 
[Item Number 3.6.1.1 (F.4)]
Degradation due to various aging
 
mechanisms Environmental Qualification of
 
Electrical
 
Components
 
ProgramTLAAThis TLAA is evaluated in
 
Section 4.4, Environmental
 
Qualification Electrical cables and connections not
 
subject to 10 CFR 50.49 EQ
 
requirements (Item Number
 
3.6.1.2)Embrittlement, cracking, melting, discoloration, swelling, or loss of
 
dielectric strength
 
leading to reduced
 
insulation resistance (IR); electrical
 
failure caused by
 
thermal/
thermoxidative
 
degradation of organics; radiolysis and photolysis [ultra
 
violet (UV) sensitive materials only] of
 
organics; radiation-induced
 
oxidation; moisture
 
intrusion Aging Management Program for
 
Electrical Cables
 
and Connections
 
Not Subject to 10 CFR 50.49 EQ
 
Requirements Aging Management Program for
 
Electrical Cables
 
and Connections
 
Not Subject to 10 CFR 50.49 EQ
 
RequirementsConsistent withGALL, which
 
recommends no
 
further evaluation (See Section
 
3.6.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-350 Electrical cables used in instrumentation
 
circuits not subject to 10 CFR 50.49 EQ
 
requirements that
 
are sensitive to
 
reduction in
 
conductor insulation
 
resistance (Item Number
 
3.6.1.3)Embrittlement, cracking, melting, discoloration, swelling, or loss of
 
dielectric strength
 
leading to reduced
 
IR; electrical failure caused by thermal/
 
thermoxidative
 
degradation of
 
organics; radiation-induced
 
oxidation; moisture
 
intrusion Aging Management Program for
 
Electrical Cables
 
Used in Instrumentation
 
Circuits not Subject to 10 CFR 50.49 EQ
 
Requirements Aging Management Program for
 
Electrical Cables
 
Used in Instrumentation
 
Circuits not Subject to 10 CFR 50.49 EQ
 
RequirementsConsistent withGALL, with exceptions, which
 
recommends no
 
further evaluation (See Section
 
3.6.2.1)Inaccessible medium-votlage
 
(2kV to 15kV)
 
cables (e.g.,
installed in conduit
 
or direct buried) not
 
subject to 10 CFR 50.49 EQ
 
requirementsFormation of water trees; localized
 
damage leading to
 
electrical failure (breakdown of
 
insulation) caused by moisture intrusion and water
 
trees Aging Management Program for
 
Inaccessible
 
Medium voltage
 
Cables not Subject to 10 CFR 50.49 EQ
 
Requirements Aging Management Program for
 
Inaccessible
 
Medium voltage
 
Cables not Subject to 10 CFR 50.49 EQ
 
RequirementsConsistent withGALL, which
 
recommends no
 
further evaluation (See Section
 
3.6.2.1)The staff's review of the BFN component groups followed one of several approaches. One approach, documented in SER Section 3.6.2.1, involves the staff's review of the AMR results in
 
the electrical and I&C components that the applicant indicated are consistent with the GALL
 
Report and do not require further evaluation. Another approach, documented in SER
 
Section 3.6.2.2, involves the staff's review of the AMR results for components in the electrical
 
and I&C systems that the applicant indicated are consistent with the GALL Report and for which
 
further evaluation is recommended. A third approach, documented in SER Section 3.6.2.3, involves the staff's review of the AMR results in the electrical and I&C components that the
 
applicant indicated are not consistent with, or not addressed in, the GALL Report. The staff's
 
review of AMPs that are credited to manage or monitor aging effects of the electrical and I&C
 
components is documented in SER Section 3.0.3.3.6.2.1  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Not Recommended Summary of Technical Information in the Application. In LRA Section 3.6.2.1, the applicant identified the materials, environments, and AERMs. The applicant identified the following
 
programs that manage the aging effects related to the electrical and I&C components:
* Accessible Non-EQ Cables and Connections Inspection Program
* Bus Inspection Program
* Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program 3-351
* EQ Program
* Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program Staff Evaluation. In LRA Table 3.6.2.1, the applicant provided a summary of AMRs for the electrical and I&C components, and identified which AMRs it considered to be consistent with
 
the GALL Report.
For component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report does not recommend further
 
evaluation, the staff performed an audit and review to determine whether the plant-specific
 
components contained in these GALL Report component groups were bounded by the GALL
 
Report evaluation.
The applicant provided a note for each AMR line item. The notes described how the information in the tables aligns with the information in the GALL Report. The staff audited those AMRs with
 
Notes A through E, which indicated that the AMR was consistent with the GALL Report.
Note A indicated that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the AMP
 
identified in the GALL Report. The staff audited these line items to verify consistency with the
 
GALL Report and the validity of the AMR for the site-specific conditions.
Note B indicated that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP
 
identified in the GALL Report. The staff audited these line items to verify consistency with the
 
GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been
 
reviewed and accepted by the staff. The staff also determined whether the AMP identified by the
 
applicant was consistent with the AMP identified in the GALL Report and whether the AMR was
 
valid for the site-specific conditions.
Note C indicated that the component for the AMR line item is different from but consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent
 
with the AMP identified by the GALL Report. This note indicates that the applicant was unable to
 
find a listing of some system components in the GALL Report. However, the applicant identified
 
a different component in the GALL Report that had the same material, environment, aging
 
effect, and AMP as the component that was under review. The staff audited these line items to
 
verify consistency with the GALL Report. The staff also determined whether the AMR line item
 
of the different component was applicable to the component under review and whether the AMR
 
was valid for the site-specific conditions.
Note D indicated that the component for the AMR line item is different from but consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some
 
exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify
 
consistency with the GALL Report. The staff verified whether the AMR line item of the different
 
component is applicable to the component under review. The staff verified whether the identified
 
exceptions to the GALL AMPs had been reviewed and accepted by the staff. The staff also 3-352 determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site-specific conditions.
Note E indicated that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited. The staff audited these line items
 
to verify consistency with the GALL Report. The staff also determined whether the identified
 
AMP would manage the aging effect consistent with the AMP identified by the GALL Report and
 
whether the AMR is valid for the site-specific conditions.
The staff conducted an audit and review of the information provided in the LRA and program bases documents, which are available at the applicant's engineering office. On the basis of its
 
audit and review, the staff found that the AMR results that the applicant claims to be consistent
 
with the GALL Report are consistent with the AMRs in the GALL Report. Therefore, the staff
 
found that the applicable aging effects were identified and are appropriate for the combination of
 
materials and environments listed.
Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating
 
experience and proposals for managing associated aging effects. On the basis of its review, the
 
staff concluded that the AMR results that the applicant claimed to be consistent with the GALL
 
Report are consistent with the AMRs in the GALL Report. Therefore, the staff concluded that the
 
applicant had demonstrated that the effects of aging for these components will be adequately
 
managed so that their intended function(s) will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).3.6.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended Summary of Technical Information in the Application. In LRA Section 3.6.2.2, the applicant provided further evaluation of aging management as recommended by the GALL Report for the electrical components. The applicant provided in formation concerning how it will manage the following aging effects:
* electrical equipment subject to EQ requirements
* QA for aging management of NSR components Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report recommends further
 
evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it
 
adequately addressed the issues that were further evaluated. In addition, the staff reviewed the
 
applicant's further evaluations against the criteria contained in SRP-LR Section 3.6.2.2. Details
 
of the staff's audit are documented in the staff's BFN audit and review report. The staff's
 
evaluation of the aging effects is discussed in the following sections.
3.6.2.2.1  Electrical Equipment Subject to Environmental Qualification Requirements
 
EQ is a TLAA requiring further evaluation. TLAAs are evaluated in SER Section 4.
3-353 3.6.2.2.2  Quality Assurance for Aging Management of Non-Safety-Related Components SER Section 3.0.4 provides the staff's evaluation of the applicant's quality assurance program.Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report, and for which the GALL Report
 
recommends further evaluation, the staff determined that: (1) those attributes or features for
 
which the applicant claimed consistency with the GALL Report were indeed consistent, and (2)
 
the applicant had adequately addressed the issues that were further evaluated. The staff found
 
that the applicant had demonstrated that the effects of aging will be adequately managed so
 
that the intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
3.6.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Table 3.6.1, the staff reviewed additional details of the results of the AMRs for MEAP combinations that are not consistent with
 
the GALL Report, or that are not addressed in the GALL Report.
In LRA Table 3.6.1, the applicant indicated, via Notes F through J, that neither the identified component nor the material and environment combination is evaluated in the GALL Report and
 
provided information concerning how the aging effect will be managed.
Staff Evaluation. For component type, material, and environment combinations that are not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine
 
whether the applicant had demonstrated that the effects of aging will be adequately managed
 
so that the intended function(s) will be maintained consistent with the CLB during the period of
 
extended operation.
The applicant's AMR results that are not consistent with the GALL Report, or not addressed in the GALL Report, were not reviewed during the onsite audit.
3.6.2.3.1  Aging Management Evaluations - Fuse Holder
 
Fuse holders (including fuse clips and fuse blocks) are included consistent with Interim Staff Guidance (ISG)-5, "Identification and Treatment of Electrical Fuse Holders for License
 
Renewal," dated March 10, 2003. ISG-05 added NRC guidance for the identification and
 
treatment of electrical fuse holders for license renewal, which stipulates that fuse holders will be
 
scoped, screened, and included in the AMR in the same manner as terminal blocks and other
 
types of electrical connections. The guidance also says that an appropriate AMP should be
 
adopted to manage the effects of aging where necessary.
Consistent with that staff guidance, the applicant identified oxidation, corrosion of connecting surfaces, moisture or chemical contamination, loosening of connection/thermal cycling, wear, fatigue, loosening of connection/vibration, deformation, and loosening of connection/mechanical
 
stresses as the aging mechanism/effects for the fuse holders.
3-354 In the LRA, the applicant stated that plant installation and maintenance practices provide appropriate protection for fuse holders from moisture intrusion, such as in enclosures, since
 
fuse holders are protected by their location within a controlled environment. Therefore, oxidation/corrosion of connecting surfaces due to exposure to moisture or chemical
 
contamination is not an AERM. The applicant also stated that fuse holders in use are designed
 
to withstand the ratings of the fuses they house. Thus, fuse holders are protected from thermal
 
cycling by their design, which prevents the aging effect of fuse clip/finger loosening, and
 
requires no AMP. Fuse holders are mounted in their own support structure separated from
 
sources of vibration; therefore, vibration is not a concern for fuse holders, and an AMP is not
 
required. The fuses are not routinely pulled and reinserted potentially causing fatigue of the fuse
 
holder clips.
Based on the above, the applicant concluded that fuse holders at BFN will maintain their intended function through the period of extended operation with no AMP required.
In RAI 3.6-5, dated November 4, 2004, the staff asked the applicant to justify how a controlled environment could provide protection for fuse holders, preventing aging from the effects of temperature, humidity, radiation, and fatigue. The staff also asked the applicant whether the
 
actual condition of the fuse holders was evaluated to assess the extent of use and whether any
 
visual inspection was performed on the fuse holders; if so, the applicant was requested to
 
provide the findings or explain why an assessment of their current condition was not necessary.
In its response, by letter dated December 9, 2004, the applicant stated:
A controlled environment, as it pertains to fuse holders, is one where the fuse holder is installed in an enclosure that protects the fuse holder from exposure to moisture and
 
chemical contamination. Enclosures at BFN are designed and selected for the
 
environment in which they are installed. National Electrical Manufacturers Association (NEMA) Standards imposed during the design process ensures the enclosure is suited
 
for the environment in which it is installed. In addition, conduits entering the enclosure
 
were sealed, along with unused knockouts. Enclosure tops and non-welded seams are
 
sealed, along with enclosure and component mounting screws/bolts. Door gaskets
 
supplied with NEMA enclosures are acceptable, or the enclosure door is sealed utilizing
 
engineering approved maintenance instructions.
The aging mechanisms of temperature and radiation are not applicable to the fuse clip portion of fuse holders, but are applicable to the polymeric base material. Polymeric
 
materials of fuse holders utilized at BFN were evaluated as insulated connections and
 
are acceptable for the extended period of operation in the environments in which they
 
are presently installed. None of the polymeric material's 60-year bounding temperature
 
or radiation values were exceeded in any plant space where fuse holders are installed at
 
BFN. By email dated December 15, 2004, the staff requested additional information on the subject. In its response, by letter dated January 18, 2005, the applicant stated that polymeric materials of
 
fuse holders are included in the Accessible Non-EQ Cable and Connections Inspection
 
Program.
3-355 On the issue of fatigue, mechanical stress due to forces associated with electrical faults and transients are mitigated by the fast action of circuit protective devices at high currents. However, mechanical stress due to electrical faults is not considered a credible aging mechanism since
 
such faults are infrequent and random in nature. Fuse holders in use are designed to withstand
 
the ratings of the fuses they house and are selected to ensure they are operated below their
 
rated load. Thus by design, fuse holder clips and connections are protected from fatigue failure
 
due to thermal cycling.
Industry operating experience as documented in NUREG-1760 "Aging Assessment of Safety-Related Fuses used in Low- and Medium-Voltage Applications in Nuclear Power Plants,"
identified that fuse failures due to thermal cycling are attributed to the fuse element, not fuse
 
holder clips. NUREG-1760 documents no instances of fuse holder clip fatigue failures attributed
 
to thermal cycling. A visual inspection performed on a sample located in outdoor weather
 
conditions did not reveal visual signs of corrosion or degradation.
On the basis of its review, the staff found that the applicant had addressed the staff's concern adequately; therefore, the staff's concern described in RAI 3.6-5 is resolved. The staff also
 
found that no AMP is required to manage the aging effects of fuse holders.
3.6.2.3.2  Aging Management Evaluations - Insulated Cables and Connections
 
In LRA Section 3.6.2.3.2, the applicant identified the electrical failures due to moisture intrusion, which was addressed in SAND 96-0344, "Aging Management Guidelines for Commercial
 
Nuclear Power Plants - Electrical Cable and Terminations," and TR-103834-P1-2, "Effects of
 
Moisture on the Life of Power Plant Cables." In evaluating these aging effects, the applicant, in the LRA, said that plant installation and maintenance practices provide appropriate protection for connectors from moisture (such as
 
connectors in enclosures or covered with Raychem tubing/splices or tape). Therefore, aging
 
effects related to moisture intrusion for low-voltage cables and connectors do not require aging
 
management for the period of extended operation. However, this aging effect/mechanism is
 
prevalent in medium voltage cables (i.e., wate r treeing) which is managed by the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification
 
Requirements Program.
The staff agreed that the applicant had correctly concluded that no separate AMP is required to manage aging effects related to moisture intrusion for low-voltage cables and connectors. The
 
staff found that the GALL Report addressed the aging effect/mechanism in inaccessible medium
 
voltage cables, which will be adequately managed by the applicant's Inaccessible Medium
 
Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements
 
Program. 3.6.2.3.3  Aging Management Evaluations - High-Voltage Insulators
 
High-voltage insulators typically used on transmission towers are insulating materials in a form designed to (a) support the conductor physically and (b) separate the conductor electrically from
 
another conductor or object. Materials used for the high-voltage insulators are porcelain and
 
metal.
3-356 In LRA Section 3.6.2.3.3, the applicant identified surface contamination, cracking, and loss of material due to mechanical wear as the aging effects/mechanism for high-voltage insulators.
In managing these aging effects, the applicant evaluated these effects as follows:
 
Surface Contamination - the buildup of surface contamination is gradual and in most areas such contamination is washed away by rain. Contam ination buildup on insulators is not a problem due to rainfall periodically washing the insulators.
Cracking - Cracking and breaking of porcelain insulators is typically caused by physical damage, which is not an aging effect and is not subject to an AMR. A review of plant-specific
 
operating experience revealed no instances of insulator cracking or failure related to cement
 
growth at the switchyard. Cracks have also been known to occur with insulators when the
 
cement binds the parts together enough to crack the porcelain. This phenomenon is known as
 
cement growth, and is caused by improper manufac turing process or materials that makes the cement more susceptible to moisture penetration. Therefore, cracking of high-voltage insulators
 
due to cement growth is not an AERM for the period of extended operation Mechanical Wear - Mechanical wear is an aging mechanism for strain and suspension insulators in that they are subject to movement. Although this mechanism is possible, industry
 
experience has shown that transmission conductors do not normally swing, and when they do
 
swing, as a result of a substantial wind, they do not continue to swing for very long once the
 
wind subsides. In the applicant's evaluation, wear has not been identified during maintenance
 
activities on BFN insulators.
The staff concluded that the applicant had adequately addressed the aging management for high-voltage insulators and agreed that no AMP was required for high-voltage insulators.
3.6.2.3.4 Aging Management Evaluations - Transmission Conductors and Connections
 
Transmission conductors are uninsulated, stranded electrical cables used in switchyards, switching stations, and transmission lines to connect two or more elements of an electrical
 
power circuit, such as active disconnect switches, power circuit breakers, and transformers, to a
 
passive switchyard bus. Typical transmission conductor materials are aluminum conductor steel
 
reinforced (ACSR).In LRA Section 3.6.2.3.4, the applicant stated that the portions of transmission conductor within the scope of license renewal for BFN are all aluminum conductors. All aluminum conductors, unlike ACSR, are not as susceptible to environmental influences, such as sulphur dioxide
 
concentration in air. When aluminum corrodes, it forms a protective oxide layer which protects
 
the underlying material from further corrosion. When the steel core of ACSR corrodes due to
 
losing its galvanized coating, it will continually corrode causing a decrease in ultimate strength
.The two types of aluminum conductors used at BFN are Orchid, 636 mcm, and Coreopsis, 1590
 
mcm, which have an ASTM rated strength of 11,000 lbs and 27,000 lbs respectively. The
 
maximum load permitted by TVA design is 3000 lbs for Orchid and 6000 lbs for Coreopsis, which results in a margin of 73 percent and 77 percent of the rated strength. Using the same percent decrease in ultimate strength of 33 percent from the Ontario Hydroelectric test, the
 
aluminum conductors at BFN would undergo a loss of rated strength of 3663 lbs for Orchid and
 
8910 lbs for Coreopsis. The new rated strength/margin of rated strength would be 7437 lbs/40 3-357 percent and 18090 lbs/44 percent for Orchid and Coreopsis, respectively. The ultimate strengths are well above TVA's maximum design load and the National Electrical Safety Code
 
margin of ultimate load, 6660 lbs for Orchid and 16200 lbs for Coreopsis, for the original
 
conductors. Although corrosion of aluminum is minimal, a decrease in ultimate strength due to
 
corrosion similar to that of the ACSR conductor tested by Ontario Hydroelectric shows that the
 
aluminum conductors at BFN will continue to perform their intended functions for the period of
 
extended operation. Further, the applicant stated that transmission and power supply personnel perform normal maintenance activities on all portions of the switchyard, including transmission
 
conductors. These maintenance activities have not revealed any aging effects/mechanisms
 
associated with transmission lines to date. In conclusion, there are no applicable aging effects
 
that could cause loss of the intended function of the transmission conductors. Therefore, loss of
 
conductor strength due to corrosion of transmission conductors is not an AERM for the period of
 
extended operation.
Industry experience has shown that transmission conductors do not normally swing, and that when they do swing in substantial wind, they do not continue to swing for very long once the
 
wind subsides. Therefore, loss of material (wear) and fatigue due to wind loading vibration or
 
sway of transmission conductors are not applicable AERMs for the period of extended
 
operation.
The applicant concluded that no AMP is required.
 
In RAI 3.6-8, dated November 4, 2004, the staff raised a concern regarding the torque relaxation for bolted connections for transmission conductor and switchyard bus connections.
In its response, by letter dated December 9, 2004, the applicant stated that bolted switchyard bus and transmission conductor connections at BFN utilize Belleville washers, which have
 
torque applied until the Belleville washer is flat, not to exceed limits specified by bolt size. In
 
accordance with industry guidance EPRI TR-104213, "Bolted Joint Maintenance & Application
 
Guide," (Section 7.2.2), increased temperature difference in electrical bolted joints is due to high
 
short circuit ratings or increased current duration. The temperature of an electrical bolted joint
 
will rise and the stress will increase with increasing current duration. If this temperature increase
 
is not taken into consideration, loose, failure-prone joints will result. Belleville washers selected
 
to be flat or almost flat at the installation torque will be used to accommodate the temperature
 
increase. At BFN, connections are routinely surveyed using infrared scan for hot spots, which
 
are indicative of a degraded connection. If a hot spot at a connection is discovered, corrective
 
actions are taken to repair the connection.
In a supplemental letter, dated January 18, 2005, in response to a staff follow-up question, the applicant stated that the infrared scans are performed using Transmission Power Supply
 
Routine Test Schedule. This schedule requires that 500 kV and 161 kV switchyard connections
 
be surveyed after a modification and routinely surveyed every six months. A review of plant-specific operating experience did not reveal any age-related issues associated with bolted switchyard bus or transmission conductor connections; therefore, torque relaxation of bolted
 
switchyard bus and transmission conductor connections is not a concern for BFN.
On the basis of its review, the staff's concern described in RAI 3.6-8 is resolved.
3-358 The staff concluded that although corrosion of aluminum is minimal, a decrease in ultimate strength due to corrosion similar to that of the ACSR conductor tested by Ontario Hydroelectric
 
shows that the all aluminum conductors at BFN will continue to perform their intended functions
 
for the period of extended operation. Also, based on the response to the staff concern regarding
 
the torque relaxation for bolted connections, the concern raised in RAI 3.6-8 was resolved. The
 
staff agreed with the applicant's evaluations and concluded that the applicant had adequately
 
addressed the aging management for transmission conductors and connections. The staff also
 
agreed that no AMP was required.
3.6.2.3.5  Aging Management Evaluations - Switchyard Bus
 
Switchyard buses electrically connect specified sect ions of an electrical circuit to deliver voltage or current to various equipment and components throughout the plant. The switchyard bus is
 
used in switchyards to connect two or more elements of an electrical power circuit such as
 
active disconnect switches and passive transmission conductors.
In LRA Section 3.6.2.3.5, the applicant identified cracking due to vibration and change in material properties leading to increased resistance and heating as a result of connection
 
surface oxidation as potential aging effects for the high-voltage switchyard bus. In managing the
 
aging effects, the applicant stated that switchyard buses connected to circuit breakers via
 
flexible aluminum conductors, those supported by insulators and by structural supports such as concrete footing or steel structures, do not vibrate. Also, the design process for switchyard bus
 
was engineered to dampen any vibrations that might be induced into the buses. Therefore, cracking due to vibration is not an applicable aging effect for switchyard buses, and an AMP is
 
not required.
The applicant also identified aging effects due to change in material properties leading to increased resistance and heating as a result of connection surface oxidation in aluminum
 
buses. Solid and flexible connectors and ground straps are highly conductive but do not make a
 
good contact surface since pure aluminum exposed to air forms aluminum oxide on the surface, which is nonconductive. To prevent the formation of aluminum oxide on bolted connection
 
surfaces, the connections have a silver plating and are covered with grease to prevent air from
 
contacting the connection surface. The grease is a consumable item that is applied to the
 
connection surface each time a bolted connection is made, thereby precluding oxidation of the
 
connection surface and maintaining good conductivity at the bus connections. Therefore, change in material properties leading to increased resistance and heating as a result of
 
connection surface oxidation of aluminum buses is not an AERM for the period of extended
 
operation.
In RAI 3.6-7, dated November 4, 2004, the staff requested the applicant to provide a discussion of the grease replacement program including the frequency.
In its response, by letter December 9, 2004, the applicant stated that grease is a consumable item that is applied each time a bolted connection is made, and that it precludes oxidation of the
 
connection surface and maintains good conductivity at the bus connections. Connections are
 
routinely surveyed using infrared scan for hot spots, which are indicative of a degraded
 
connection. In its response, the applicant stated that if a hot spot at a connection is discovered, corrective actions are taken to repair the connection. In a supplemental response, dated
 
January 18, 2005, to a staff follow up-question, the applicant stated that the infrared scans are 3-359 performed using the Transmission Power Supply Routine Test Schedule. The Transmission Power Supply Routine Test Schedule states that 500 kV and 161 kV switchyard connections are
 
surveyed after a modification and routinely surv eyed every six months. On the basis of its review, the staff found that its concern described in RAI 3.6-7 is resolved.
The staff concurred with the applicant's evaluation and concluded that no AMP is required to manage these components. The staff also found that the applicant had adequately addressed
 
why these aging effects are not applicable aging effects at BFN. The staff agrees that there is
 
reasonable assurance that the switchyard bus will perform its intended function for the period of
 
extended operation.
Conclusion. On the basis of its review, the staff found that the applicant had appropriately evaluated AMR results involving MEAP combinations that are not evaluated in the GALL
 
Report. The staff found that the applicant had demonstrated that the effects of aging will be
 
adequately managed so that the intended functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
====3.6.3 Conclusion====
The staff concluded that the applicant had provided sufficient information to demonstrate that the effects of aging of the electrical and I&C components that are within the scope of license
 
renewal and subject to an AMR will be adequately managed so that the intended function(s) will
 
be maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
The staff also reviewed the applicable UFSAR supplement program summaries and concludes that they adequately describe the AMPs credited for managing aging of the electrical and I&C
 
components, as required by 10 CFR 54.21(d).
3-3603.7  Aging Management Review of Unit 1 Systems in Layup for Extended Outage
 
====3.7.1 General====
Technical Concerns LRA Section 3.0.1 contains a summary of t he evaluation of systems and components subjected to the Unit 1 layup and preservation program. Staff initially reviewed LRA Section 3.0.1 and
 
determined that additional information was required. By letter dated February 19, 2004, the
 
applicant submitted a supplement to the LRA dedica ted to the Unit 1 systems in layup during the extended outage. The staff then issued a series of RAIs to obtain additional information on
 
the aging management of components subjected to layup conditions during the extended outage. During the staff review, it was determined that license renewal and plant restart were to
 
be decoupled and, as a result, plant changes to support restart were to be primarily evaluated
 
independently as part of the restart effort. The staff focused its layup and preservation program
 
review on consistency with industry guidance, operating experience including restart
 
inspections, potential latent aging effects, and the adequacy of one-time inspections to manage
 
systems not in service during the extended outage.
In addition to the layup and preservation program, a combination of factors related to operating experience contribute to the way aging effects ar e managed for systems that were not in service during the extended outage. Those factors are addressed below.
* Length of Extended Outage - The Unit 1 extended outage lasted for approximately twenty years. The length of this extended outage was significantly longer than the
 
extended outage for either Unit 2 or Unit 3 and is unique in the industry. The extended outage limited the amount of Unit 1 operating experience available for review and
 
created abnormal internal environments that contributed to aging.
* Limited Operating Experience - The length of the Unit 1 extended outage limited the amount of operating experience and data available for use in aging management
 
reviews. Unless there is sufficient data available, one-time inspections may not be
 
appropriate to manage systems that were not in service during the extended outage. In response to Item 5.B, discussed below, the applicant provided additional information
 
concerning Units 2 and 3 restart programs and layup operating experience that is
 
applicable to Unit 1.
* Replacement of Components - LRA Appendix F identified that large portions of systems and components were replaced. The basis for material replacement was either the result
 
of excessive degradation caused by ineffectiv e layup practices or potential susceptibility to known degradation mechanisms. The primary concern for aging management is
 
associated with components that were not replaced.
* Suspension of Maintenance Rule - By letter dated August 9, 1999, the staff issued a temporary partial exemption from 10 CFR 50.65 for Unit 1. This partial exemption provided relief from the Maintenance Rule for systems that were not in service to support
 
Units 2 and 3.
3-361 Evaluation Findings SER Section 3.7 contains the staff evaluation of Unit 1 systems subject to layup conditions during the extended outage. SER Section 3.7 includes an evaluation of general technical
 
concerns and system-specific concerns relevant to systems and components subjected to layup conditions. This evaluation determined that, due to a number of factors including (1) service
 
conditions resulting from potentially ineffective layup practices, (2) the length of the extended outage period, (3) limited operating experience, (4) replacement of degraded material due to
 
ineffective layup practices, and (5) suspension of maintenance activities for systems subject to
 
layup, periodic inspections would be more appropriate than one-time inspections to manage
 
aging effects in systems that were subject to layup conditions, where latent aging effects may
 
have existed. The applicant agreed to a periodi c inspection program to manage systems that were not replaced and were not in service during the extended outage. Details of the program
 
were not available at the time the SER with open items was prepared. The ACRS interim report
 
dated October 19, 2005, agreed with staff that additional information was required to support
 
the staff review of the wet layup sections and periodic inspection program versus one-time
 
inspection program.
Unresolved Items By letter dated October 31, 2005, the staff summarized the following unresolved items related to the layup and preservation program and requested the applicant to provide additional
 
information to address unresolved items raised in the committee's interim report:
* Providing suitable input for the wet layup sections for the SER so that the staff can write a cohesive safety evaluation on the applicability of Units 2 and 3 experience to Unit 1.
* Clarification of One-Time Inspection Program versus Unit 1 Periodic Inspection Program and One-Time Inspection Program consistency with the GALL Report.
The applicant, by letter dated November 16, 2005, submitted additional information, discussed below, to close out the unresolved items re lated to systems subject to the layup and preservation program.
Restart Programs and Unit 2 and 3 Layup Operating Experience Applicable to Unit 1 BFN Unit 1 was licensed and began initial operation in 1973. Unit 2 began operation in 1974.
Units 1 and 2 operated until March 22, 1975, at which time both units were shut down due to a
 
fire in the Unit 1 reactor building. Units 1 and 2 resumed operation in 1976 and Unit 3 began
 
initial operation in 1977. All three units were operated until March 1985, at which time the
 
applicant voluntarily shut them down to address regulatory and management issues.
Following successful resolution of the management issues and the Unit 2 and common regulatory issues, Unit 2 was restarted on May 23, 1991. Unit 3 remained in a layup/recovery
 
mode for approximately 10 years and, following resolution of the Unit 3 regulatory issues, it was
 
restarted on November 19, 1995. Both units have operated with high capacity factors into the
 
present time. In the early 1990s, the applicant decided to defer restart of BFN Unit 1.
3-362 On May 16, 2002, the applicant announced the Unit 1 restart project. As part of the Unit 1 restart project, the applicant is performing the same restart programs and implementing the
 
same modifications that were previously completed on Units 2 and 3. At restart, Unit 1 will be
 
operationally the same as Units 2 and 3. The current planned Unit 1 restart date is May 2007.
The Unit 1 systems that perform a required function in the defueled condition, or that directly support Unit 2 or Unit 3 operation, have been continuously operated and maintained under
 
applicable technical specifications and plant programs since shutdown in 1985. Examples of
 
these systems are:
* fuel pool cooling system
* portions of the control rod drive (CRD) system
* portions of the raw cooling water (RCW) system
* portions of the reactor building closed cooling water (RBCCW) system
* portions of the residual heat removal (RHR) system
* portions of the residual heat removal service water (RHRSW) system
* portions of the emergency equipment cooling water (EECW) system
* portions of the control air system The applicant maintained the Unit 1 systems in a physical condition during shutdown similar to that of Units 2 and 3 during their shutdown periods. The internal operating conditions (e.g.,
water chemistry, flow rate, temperature, etc.) for these systems are the same as those found in
 
the operating units. These systems have exper ienced the same aging mechanisms and rates experienced by similar Units 2 and 3 systems for shutdown conditions. The Units 1, 2, and 3 reactor buildings are one continuous structure, and the external operating environments of the
 
systems are the same.
Even though Unit 1 was in an extended outage, the overall environmental conditions affecting external surfaces in Unit 1 was maintained consistent with those of Units 2 and 3. Unit 1 had the normal ventilation systems in service and equipment was
 
maintained to prevent system leakage so that the equipment was not subjected to aggressive
 
external conditions.
Unit 3 was shut down for approximately 10 years: from 1985 to 1995. The aging effects on Unit 3 were monitored and addressed prior to startup in 1995. Since 1995, Unit 3 has operated with
 
a high capacity factor and was uprated 5 percent reactor thermal power in 1998. During this
 
10-year period of operation, no additional aging effects have been identified attributable to the
 
10 years of shutdown and layup. Since Unit 1 was laid up and maintained using the same
 
method as Unit 3, the aging effects during the layup and subsequent operation of Unit 3 would
 
be expected to apply equally to Unit 1. Unit 2 and 3 operations, including power up-rate, have
 
not resulted in any unexpected aging mechanisms or rates. Unit 1 operation, following the
 
shutdown and associated replacements/refurbishments, is expected to exhibit the same aging
 
mechanisms and rates as Units 2 and 3.
Other Unit 1 systems have been in a layup conditi on, and prior layup experience from Unit 3 has been applied to Unit 1 license renewal. Some piping systems (or portions of piping systems) were placed in a "wet layup" under the applicant's Unit 1 layup procedure, including:
* reactor vessel
* reactor water recirculation system
* reactor water cleanup system 3-363
* portions of the RHR system
* portions of the core spray (CS) system
* portions of the feedwater (FW) system The water chemistry within these Unit 1 piping systems was monitored for compliance with the water quality requirements. Thus, it would not be expected that a different aging mechanism or
 
rate would exist in wet layup compared to w hat would have occurred if the system were in normal operation. The full scope of BWRVIP inspections have been performed on the Unit 1
 
reactor vessel as part of the restart project. No adverse effects from the layup period were found
 
and repairs/replacements not related to layup will be performed as required. The reactor water
 
recirculation system and reactor water cleanup system piping, both large bore and small bore, have been replaced. The RHR and CS piping that was in wet layup has also been replaced. The
 
piping was replaced with the same materials that were used in Units 2 and 3. Ultrasonic
 
inspections of the feedwater piping have conf irmed that the piping does not exhibit adverse effects from the wet layup period.
Some Unit 1 piping systems (or portions of piping systems) were drained and placed in dry layup, including:
* reactor core isolation cooling (RCIC) system
* high pressure coolant injection (HPCI) system
* main steam (MS) system
* portions of the RHR system
* portions of the CS system
* portions of the FW system The exterior of the system/component was mainta ined at nominal reactor or turbine buildings ambient conditions which would have been the same in Units 1, 2, and 3. Thus, the dry layup
 
systems would have experienced aging at a rate less than or equal to that of the corresponding
 
Unit 2 or Unit 3 system.
Some Unit 1 systems were simply drained with no controlled environment. As a result, portions of two Unit 1 systems experienced accelerat ed aging. The accelerated aging of these systems was previously identified as part of the oper ating experience from the Unit 3 outage between 1985 and 1995. These were portions of the Unit 1 RHRSW piping inside the reactor building
 
and some small bore raw cooling water piping. As explained below, this prior Unit 2 or Unit 3
 
operating experience was incorporated into Unit 1 aging management activities.
The RHRSW piping normally contains raw water from the river. Some of the Unit 1 RHRSW piping inside the reactor building was drained in 1985, but moisture-laden air remained in the
 
system. The piping enters/exits from the RHRSW tunnels. Inside the tunnels, the piping is
 
exposed (i.e., not buried) for approximately 100 feet after which it becomes buried pipe out to
 
the intake pumping station. The buried piping could not be drained since it is below grade.
 
Water from the buried section of piping vaporized and entered the drained, above-grade piping
 
in both the tunnels and the reactor building. Inside the RHRSW tunnels, which are
 
approximately 20 feet under an earthen berm, the ambient temperature was cool and no
 
adverse reactions occurred inside the RHRSW piping. However, the RHRSW piping inside the reactor building experienced normal ambient conditions (i.e., 65 &deg;F to 90 &deg;F). In this warm, moisture-laden environment, severe corrosion occurred necessitating complete replacement of 3-364 the pipe. As shown by ultrasonic measurements of pipe wall thickness and visual observations of pipe interiors, this aging effect was not experienced by buried pipe or above grade pipe that
 
was full of water. This aging effect was restricted to the RHRSW system because it is the only
 
system that was drained but allowed to contain moisture-laden air. This aging was first identified
 
on Unit 3 during the Unit 3 recovery and necessitated the replacement of all of the RHRSW
 
piping inside the Unit 3 reactor building. Based on this lesson learned, the required pipe
 
replacement was performed for the Unit 1 A and C loops of RHRSW piping, which had been in a
 
similar layup fashion to the Unit 3 piping.
The small bore RCW piping was drained; however, due to valve leakage, some water was reintroduced into the system. The combination of water and trapped air set up virtually the same
 
corrosion effects described above for the RHRSW piping. The Unit 1 recovery project has
 
visually and ultrasonically inspected the small bore raw water piping and is replacing
 
approximately 3000 feet of degraded piping.
The Unit 1 restart project did not credit the Unit 1 layup program as the sole means of establishing the acceptability of the associated piping and components for restart. TVA either replaced the piping and components or performed appropriate visual and/or ultrasonic inspections to establish the physical condition of systems and components not being replaced, as discussed in the applicant's letter to the staff, dated May 18, 2005. For systems, piping, and components that were replaced, no layup effects are present. The Unit 1 structures, systems, and components within the scope of license renewal will be subject to the existing BFN aging
 
management programs. As a compensatory m easure for systems and components not being replaced, the applicant will perform targeted periodic inspections for the Unit 1 systems that
 
were not replaced as part of the Unit 1 restart project. These inspections will provide heightened
 
assurance that existing AMPs address relevant aging mechanisms and effects for Unit 1.
To ensure there are no latent aging effects as a result of the layup program, BFN will implement a targeted periodic inspection program for Unit 1 system piping that was not replaced as part of
 
the Unit 1 restart project. The restart inspection will provide baseline measurements for targeted
 
inspections to be performed after the unit is returned to operation to verify aging management
 
program effectiveness and to verify the absence of additional latent aging effects. The selected
 
sample will be examined by the same or equivalent methodology as used during Unit 1 restart.
 
Systems (or portions of systems) where peri odic inspections will be performed include MS, FW, RHRSW, RCW, EECW, fire protection, reactor building closed cooling water, RCIC, HPCI, RHR, and CRD.
After restart in 2007, Unit 1 would have six years of operation remaining in the current license period, prior to the period of extended operation. The first periodic inspection will be performed
 
during the current license period. An inspection also will be performed during the period of
 
extended operation. Subsequent inspection frequency will be determined based on the
 
inspection results. Inspections will continue until the trend of results provides a basis to
 
discontinue the inspection. There is reasonable confidence that these periodic inspections will
 
be capable of detecting degradation caused by potential latent aging effects after the systems
 
are returned to service.
As part of the AMR in support of the LRA, the applicant recognized that due to the layup period the Unit 1 operating experience may not be the same as the operating experience for Units 2
 
and 3. Thus, as a further compensatory action, the applicant performed evaluations to identify 3-365 new aging effects that could be applicable to Unit 1 as a result of the layup environment. The material groupings and aging effects were established using the same approach utilized in the
 
rest of the LRA. A detailed evaluation was performed for 19 Unit 1 systems. It was concluded
 
that there were no new AERMs during the renewal term. A summary of these evaluations is
 
provided in LRA Section 3.0.1. The applicant provided additional details of this evaluation in its
 
letter to the staff dated February 19, 2004.
As part of its review of the applicant's LRA, the staff, by letter dated August 23, 2004, identified areas where additional information was needed to complete its review. The specific staff
 
questions were from LRA Sections 3.1, 3.2, 3.3, and 3.4 and were related to aging of
 
mechanical systems during the extended Unit 1 outage. Listed below are the specific staff
 
requests for additional information, responses to a number of staff follow-ups, and the LRA.
 
There were no additional aging effects because of the extended outage of Unit 1 and, consequently, the applicant claimed that there was no need for any additional aging
 
management. However, in its letter dated August 23, 2004, the staff said that since the aging of
 
mechanical systems is highly dependent on the environment maintained during the extended
 
outage, the staff needed additional information to determine whether:
* Additional or more severe aging occurred during the extended outage.
* Additional aging has been properly identified, evaluated, and managed.
* The proposed aging management can distinguish the aging during the extended outage from the aging during future operation.
 
By the initial set of RAIs dated August 23, 2004, the staff issued general and system-specific
 
RAIs on the aging of mechanical systems during the extended outage of Unit 1. The applicant responded to the initial RAIs by letter dated October 8, 2004. The staff reviewed the applicant's
 
RAI responses and, by letter dated December 16, 2004, requested additional information in a
 
set of follow-up RAIs. The applicant responded to these RAIs by letters dated January 20, and
 
January 31, 2005. System-specific RAIs are identif ied by a system-specific LRA prescript and a subscript "LP" to designate a layup RAI. Finally, the applicant resolved all the staff issues regarding the Unit 1 layup by its responses dated May 18, and May 27, 2005. RAIs (3.0-1 LP
 
through 3.0-11 LP) are applicable to all systems.
Given below are the safety evaluations of technical areas in which the staff had specific concerns relative to the Unit 1 system in the
 
extended layup and its rationale for acceptance.
3.7.1.1  Wet Layup Program Chemistry Control In the wet layup for Unit 1, the applicant characterized chemistry for the wet layup water as flowing, air-saturated, and demineralized. Since in the BFN plant only the systems carrying the
 
reactor cooling water are included in the wet layup program, the chemistry of the demineralized
 
water has the same chemistry as the cold shutdown reactor cooling water during normal plant
 
outages. The initial set of general RAIs that are referenced in the discussion that follows constitutes the staff request dated August 23, 2004. The applicant's responses are in its letter dated October 8, 2004.
3-366 In its response to RAI 3.0-1 LP by its letter dated October 8, 2004, the applicant stated that the other plant systems with different plant chemistries were not included in the wet layup program
 
because during the Unit 1 outage they were maintained at the operating conditions, including
 
water chemistries, found in Units 2 and 3 during their normal operations. The cold shutdown
 
chemistry is specified in the BFN CI-13.1 chemistry program. In the response to the staff's
 
question the applicant stated that the chemistry control limits implemented during wet layup are 1.5 &#xb5;S/cm for water conductivity, and 15 ppb for the concentration of chloride and sulfate.
 
These values are the same as the chemistry control limits utilized in Units 2 and 3 operating in
 
the cold shutdown mode for refueling and maintenance outages. They are more restrictive than
 
those in the EPRI Water Chemistry Guidelines specified in BWRVIP-79 and, therefore, introduce conservatism to the values of the CI
-13.1 chemistry program used to specify water chemistry during the wet layup.
Since water conductivity and concentration of chlorides and sulfates are the main parameters characterizing water chemistry, as long as they don't differ, the wet layup and cold shutdown
 
chemistries are comparable. The staff concurred, therefore, with the applicant that the effect of
 
chemistry on the components in wet layup and co ld shutdown will be similar, and the exposure of the components to the wet layup chemistries w ill be similar to the effect of the exposure to reactor water during the cold shutdown mode of operation.
3.7.1.2  Replaced Components LRA Appendix F indicates that significant sections of piping and components have been or will be replaced prior to Unit 1 restart. It was not clear to the staff whether LRA Appendix F included
 
all piping that had been or would be replaced prior to restart. The applicant's responses to staff
 
RAI for LRA Section B.2.1.4, developed during the license renewal audit inspection during the
 
weeks of June 21 and July 26, 2004, state that repaired or replaced components will receive a preservice examination in accordance with the requirements of IWB, IWC, or IWD of the
 
component being repaired or replaced, and prior to returning the system to service. In this
 
response, the applicant also stated that a re-baseline inspection will be performed on the
 
remaining Class 1, 2, and 3 components that have not been repaired or replaced.
In RAI 3.0-9 LP (refurbished vs left in place), dated December 16, 2004, the applicant was requested to provide information to identify the basis, such as inspections or suspected
 
degradation, to determine which components need to be replaced and those that do not. Also, the applicant was requested to clarify whether Appendix F includes all piping and components
 
that will be replaced prior to startup and to identify in a simplified boundary diagram those
 
specific sections of piping and components that have recently been or will be replaced and
 
those that have not been replaced. Further, the applicant was requested to clarify appropriate
 
layup or cleanliness programs (Refer to RAI 3.0-11 LP) and inspections that are in use and
 
planned for these components. For those system s or portions of systems and components that have not been recently replaced and were subject to the extended layup, the applicant was
 
requested to provide the information requested in RAI 3.0-10 LP (inspection information, concerning inspections).
In its response, by letter dated January 31, 2005, the applicant stated that the overall management philosophy for the Unit 1 restart was to return the plant to operation in a condition
 
that would support long-term safe and reliable operation of the unit, including the 3-367 20-year period following license renewal. The applicant further stated that, with this management philosophy as a basis, it had applied lessons learned from the Units 2 and 3
 
restart programs and operating experience from all three units in its decision to replace large
 
portions of key piping systems. The RAI 3.0-9 LP response also states that the Unit 1 restart
 
project did not credit the layup program as the sole means of establishing the acceptability of
 
the associated piping and components. Rather, the applicant either replaced the piping and
 
components or performed appropriate inspections to establish the physical condition of systems and components not being replaced.
The applicant's response to RAI 3.0-9 LP also states that LRA Appendix F did not include all piping and components that will be replaced prior to startup.
In summary, the RAI response concluded that the application of the targeted sampling inspections and the number of inspections performed has established a high level of confidence
 
that those systems with any question about their integrity have been identified, inspected, and
 
properly addressed relative to the replacement or non-replacement of the piping system and/or its components. The combination of piping replac ements identified through previously identified design issues, operating experience, and other inspections identified approximately 16,000 feet
 
of large bore piping and 26,000 feet of small bore piping to be replaced. The applicant further
 
stated that the results of the reviews of operating experience, design issues, and inspections is
 
provided in Table 1 of the RAI response. The systems listed are those in which significant piping
 
or components were identified for replacement or refurbishment. In its response, the applicant
 
presented in Table 2 of the submittal dated January 31, 2005, the details and extent of the RPV vessel inspection project (VIP) inspections and ASME Section XI re-baseline inspections that will be conducted on Unit 1 piping systems prior to operation. Finally the applicant stated that
 
the re-baseline effort is equivalent to performing a complete 10-year interval's quantity of
 
examinations during the Unit 1 restart effort.
The staff reviewed the applicant's response to RAI 3.0-9 LP and found the response to be reasonable and acceptable to clarify the general scope of replaced and refurbished components
 
including the basis for replacing certain components and not others. The applicant's response
 
and the staff's evaluation of the response is included in the applicable section for each system.
The applicant's response to RAI 3.0-9 LP states that LRA Appendix F did not include all piping and components that will be replaced prior to startup. As a result, LRA Appendix F cannot be
 
used as a means to distinguish between secti ons of piping systems and components that have been replaced and those that have not been replaced. Although the response to RAI 3.0-9 LP
 
identifies examples of piping systems and co mponents that have been replaced, the staff is unable to identify specific components that have not been replaced that were subject to layup
 
conditions. Further, the scope and results of sample inspections, including the sampling basis, have not been identified. To identify the scope and condition of components subject to Section XI or VIP inspections, the applicant was requested to identify the sampling basis and
 
inspection results for piping systems and component s subject to layup conditions that have not been replaced. The staff identified this as an unresolved issue (URI). The staff discussed this
 
issue with the applicant in follow-up teleconferences. The following is a disposition of the
 
resolution of the issues in the staff follow-ups, as documented in subsequent applicant
 
submittals.
3-368 The applicant's response, by letter dated May 18, 2005, clarified its response to RAI 3.0-9 by stating that a large amount of piping in the drywell and reactor building had been replaced, but
 
the majority of the piping had been inspected and determined to be acceptable without
 
replacement. The applicant submitted a table to identify the UT examinations performed to
 
demonstrate that the existing piping has wall thickness in excess of the manufacturer's
 
minimum nominal wall thickness (>87.5 percent of nominal) and did not require replacement.
 
The non-replaced piping inspected included the RHRSW, fire protection, emergency equipment
 
cooling water (EECW), raw cooling water (RCW), CRD, core spray, feedwater, HPCI, main
 
steam, reactor core isolation cooling (RCIC), RHR, and RBCCW systems. The locations chosen
 
for thickness examinations were susceptible areas that may have contained moisture during
 
layup, or where engineering evaluation determined wear may have occurred. By letter dated
 
May 27, 2005, the applicant submitted an additional clarification that the susceptible locations
 
were those areas determined to have the highest potential for service-induced wear or latent
 
aging effects, which include all types of corrosion. The applicant also clarified that the inspection
 
techniques utilized evaluate internal conditions and are sensitive to the presence of
 
unacceptable conditions including wear, erosion, corrosion, including crevice corrosion if
 
present. By letter dated November 16, 2005, the applicant further clarified that visual and/or
 
ultrasonic inspections establish the physica l condition of systems and components not being replaced.The staff reviewed the applicant's response and found the response acceptable. The applicant clarified that, for piping not replaced that was in a layup condition during the extended outage, UT examinations had been performed at susceptible locations having the highest potential for
 
service-induced wear or latent aging effects to demonstrate that adequate wall thickness exists.
 
There is reasonable assurance that a combination of internal visual inspections and UT
 
inspection techniques applied are adequate to detect wear, erosion, and corrosion, including
 
crevice corrosion. There is also reasonable assurance that the Corrective Action Program will
 
continue to be applied to repair or replace degraded material identified in the inspections prior to
 
adversely affecting the component intended function. Therefore, all issues related to the staff
 
issue on replaced components are resolved.
3.7.1.3  Inspections Verification Programs for Layup and Chemistry Control The SER with open items (OIs) issued on August 9, 2005, loosely used the terms "One-Time Inspection," "Restart Inspection," and "Periodic Inspection." The ACRS, in its 526 th committee meeting and subsequently in its Interim Report dated October 19, 2005, asked the staff to
 
provide clarity on these inspection terms and for the final SER to correctly reflect the intent of
 
the inspections to be performed. Accordingly, the staff sought clarifications on these terms. In its
 
submittal, by letter dated November 16, 2005, the applicant provided the following definitions of
 
the inspection terms and clarified its interpretation of these inspections in previous submittals (RAI 3.0-10 LP, responses to URIs 3.0-2 LP, 3.0-3 LP, and 3.0-4 LP). The staff has since
 
reviewed the SER with OIs and the final SER reflects the use of these definitions as provided
 
below: One-Time Inspection - The applicant's One-Time Inspection Program, B.2.1.29, isconsistent with GALL AMP XI.M32, "One-Time Inspection." These inspections include measures to verify that unacceptable degr adation of any reactor system component is not occurring, validating the effectiveness of existing AMPs or confirming that there is no
 
need to manage aging-related degradation for the period of extended operation.
3-369 Restart Inspection - These inspections are used as a means of verifying the material conditions of the system(s) of interest prior to the Unit 1 restart. These are performed
 
prior to restart. These inspections are implemented to return Unit 1 to operation for the
 
remainder of the current licensed operating period. In its submittal, by letter dated
 
November 16, 2005, the applicant stated that the restart program does not take credit for
 
the layup in returning a system to operations and instead depends on inspections and/or
 
replacement to ensure the components are satisfactory for the remainder of the current
 
licensed operating period.
Unit 1 Periodic Inspections - These inspections are for Unit 1 systems that have been shutdown during the extended layup and that were not subsequently replaced as a part
 
of the Unit 1 restart project. These are targeted periodic inspections that will be
 
performed on chosen systems after Unit 1 is returned to operation. The intent is to verify
 
the effectiveness of AMPs and to verify that no additional latent aging effects are
 
occurring. The staff agreed that the results from the Unit 1 restart inspection can be
 
used as a first set of data points. These inspections are periodic in nature and performed
 
prior to and during the period of extended operation until the applicant determines that
 
no unacceptable degradation is occurring. The applicant's Unit 1 Periodic Inspection
 
Program is described in AMP.B.2.1.42.
Systems Maintained in Dehumidified Air - The staff reviewed information presented in LRA Table 1 supplement dated February 19, 2004, on wet layup and determined that additional
 
information was required. In RAI 3.0-2 LP, dated August 23, 2005, the staff requested the
 
following additional information on Table 1 components in dry layup.
For the systems covered by Table 1, the applic ant stated that during layup, the systems were maintained in dehumidified air (60 percent relative humidity) and no additional
 
aging effects were identified for the layup condition.
NRC Inspection Report 50-259/87-45 reported that in 1987 an acceptable program for monitoring the relative humidity of all pipe environments had not been finalized and the
 
extent to which all parts of each system was being continually purged with dry air had
 
not been established. For example, the standby liquid control system contained moisture in portions of the system and procedures did not require the system to be monitored for dryness. Although inadequacies in the program were later resolved, it appears that the
 
moisture concerns existed for an extended period of time.
Also, industry documents such as EPRI NP-5106, "Sourcebook for Plant Lay-up and Equipment Preservation," revision 1, identify the need to monitor the effectiveness of the
 
layup practices. This document states that relative humidity (RH) cannot be used alone
 
as a layup surveillance technique to evaluate layup effectiveness.
Table 1 does not identify any additional inspections prior to Unit 1 restart to assess the condition of these systems, and it is not clear if inspections were performed in the layup
 
condition. In light of the above inspection findings, the recommendations in the industry
 
documents, and the possibility that parts of this system may not have been continually
 
purged with dry air (such that the exact dryness of the surrounding air cannot be
 
ascertained), discuss any inspections planned before startup to address the potential 3-370 aging during the extended outage, and whether these inspections target system low points where condensate and/or chemicals could accumulate. If inspections have been
 
performed recently, discuss the results of the inspections. If no inspections to verify the
 
aging during the extended outage are planned, provide justification for not performing
 
such inspections. Describe the process that was used to maintain equipment in a dry
 
layup condition. Discuss how humidity was controlled and maintained below 60 percent, whether the 60 percent is relative to the coldest portion of the system, the results of any
 
monitoring and trending of the air quality and humidity, and the corrective actions taken (including any inspections) for any conditions where the humidity criterion was exceeded (including corrective actions for the conditions identified in the above inspection report).
 
Also, Table 1 identifies that future one-time inspections are planned. Discuss how the
 
one-time inspections will differentiate between the rate of aging in the different
 
environments (operation vs. shutdown), and discuss whether the one-time inspections
 
will target locations that are susceptible to aging during normal operation or during
 
shutdown.In its response, by letter dated October 8, 2004, the applicant stated that, for components within the dry layup systems, a one-time inspection (restart, per letter dated November 16, 2005) will
 
be performed prior to Unit 1 restart to verify the material condition. The applicant further stated
 
that the One-Time Inspection Program does not differentiate between the rate of aging in
 
different environments (i.e., normal power operation versus cold shutdown).
Components in a Lubricating Oil Environment. - In RAI 3.0-4 LP, dated August 23, 2004, the staff requested the following additional information for managing components exposed to a
 
lubricating oil environment.
For components in a lubricating oil environment, the LRA identified no AERMs. The applicant was requested to discuss how the lubricating oil was maintained during the extended outage.
 
The applicant was also requested to discuss whether testing was performed to verify the oil
 
qualities, including moisture, that would affect aging. If the lubricating oil was drained, the
 
applicant was requested to discuss the resulting environment and any applicable aging
 
degradation. The applicant was further requested to discuss any planned inspections to verify
 
that there was no significant aging during the extended outage.
In its response to RAI 3.0-4 LP, dated October 8, 2004, the applicant stated that no maintenance or testing was performed for the re circulation system lubricating oil environment during plant layup. However, this lubricating oil environment is being deleted by design change
 
notice (DCN) 51219A, which replaces the recirculation pump MG sets with a variable frequency
 
drive. This modification has been installed on Units 2 and 3 and will be installed on Unit 1 prior
 
to restart.
The applicant further stated that no maintenance or testing was performed for the reactor core isolation cooling system or the HPCI system lubricating oil environment during plant layup.
However the applicant clarified that a sample of components with a lubrication oil environment
 
within these systems will be inspected for the following aging effects by the One-Time
 
Inspection Program.
* carbon and low-alloy steel - loss of material due to general corrosion, crevice corrosion, pitting corrosion, and galvanic corrosion 3-371
* stainless steel - loss of material due to crevice corrosion and pitting corrosion
* copper and copper alloys - loss of material due to crevice corrosion, pitting corrosion, galvanic corrosion, and selective leaching
* cast iron and cast iron alloys - loss of material due to general corrosion, crevice corrosion, pitting corrosion, galvanic corrosion, and selective leaching Systems Exposed to Air/Gas Environment - In RAI 3.0-5 LP, dated August 23, 2004, the staff requested the additional information for system s exposed to an air/gas environment. Tables 2 and 3 show that some components are exposed to an air/gas internal environment during
 
normal operation, but state that this environment is not applicable during the extended outage.
 
These tables state that, due to drainage and system isolation, portions of several systems may
 
have been exposed to an internal environment of moist air. These tables also state that the
 
evaluation for treated water encompasses the aging effects for a moist air environment in these systems. However, Tables 2 and 3 identify additional aging effects for moist air than they identify for treated water (for example, cracking in low points where condensation and chemicals can accumulate). Clarify the above discrepancy in Tables 2 and 3. Also, since the rate of loss of
 
material caused by a moist air environment during layup may be more severe than a flowing
 
treated water environment, explain why the evaluation of the aging effects for the treated water
 
environment would encompass that of the aging e ffects for a moist air environment in these systems. Tables 2 and 3 state that one-time inspections are planned for the components that
 
are exposed to an air/gas internal environment. The applicant was requested to discuss the
 
plans for additional inspections before startup of Unit 1 to evaluate aging during the extended
 
outage, or inspections that were performed during the extended outage. If no such inspections
 
are planned or none have been performed, provide justification that they are not needed and
 
discuss how the one-time inspection will distinguish between the rate of aging in the different
 
environments.
In its response to RAI 3.0-5 LP, dated October 8, 2004, the applicant stated that Table 2 Systems [RVIs, Feedwater (03), Reactor Vessel Vents and Drains (10), Reactor Recirculation (68), Reactor Water Cleanup (69) and Control Rod Drive (85)] and Table 3 Systems [Condenser Circulating Water (27), Gland Seal Water (37), Containment (64), Reactor Core Isolation
 
Cooling (71), High Pressure Coolant Injection (73), and Core Spray (75)] address the portions of
 
these systems laid up in a wet environment. Due to closure sequence, closure timing, and
 
possible leakage past the double isolation valves or two drain valves for these systems, it is
 
assumed that an air/gas environment with an uncertain amount of moisture was trapped
 
between the double isolation valves. The trapped moisture between the double valves was
 
considered the same, (i.e., treated water or raw water) as water flowing through the valves prior
 
to closure. N/A (not applicable) denotes that this trapped air/gas environment will be evaluated
 
under the corresponding raw or treated water evaluations.
The applicant further stated that during layup the temperature of the systems addressed inTables 2 and 3 were less than 140 &deg;F. Therefore, crack initiation and growth due to SCC is not a
 
concern for stainless steels and nickel-based alloys in a wet layup environment.
The applicant clarified that the evaluation of these moist air environments for the systems addressed in Tables 2 and 3 identified no additional aging effects other than those identified for
 
the corresponding raw or treated-water environment. The LRA identified these trapped air
 
environments for restart inspection because the extent of corrosion could be quantified. It was 3-372 not the intent of this AMR to determine the rate of loss of material, but only to verify its material condition. The applicant stated that the inspection will be performed prior to Unit 1 restart.
Systems Not Part of Wet Layup Program - In RAI 3.0-6 LP, dated August 23, 2004, the staff requested the following additional information on systems that were not part of the wet layup
 
program and were exposed to stagnant treated (non-controlled) or raw water.
Table 3 of Evaluation of BFN Unit 1 Lay-up and Preservation Program (submittal dated February 19, 2004) identifies several systems that were not incorporated into the Unit 1 wet
 
layup program. These systems were exposed to tr eated (non-controlled) or raw water during the extended outage. Table 3 concluded that there is no additional aging management for these
 
systems. The staff required additional information on the following: (1) discussion of the results
 
of any water samples, including pH, oxygen levels, aggressive chemical species, biological
 
activity, and corrosion product levels, (2) discussion whether the systems were stagnant or
 
periodically flowed, (3) discussion whether the plans for prestartup inspections to determine the
 
loss of material due to general, pitting, and crevice corrosion, MIC, dealloying, and galvanic
 
corrosion, or provide justification that such inspections are not needed, and (4) also, discussion
 
of inspections for the degradation of other materials, such as elastomers and other non-metallic materials.
In its response to RAI 3.0-6 LP, dated October 8, 2004, the applicant stated:
Condenser Circulating Water System (27) - System 27 was exposed to Tennessee River water which is the same environment it is exposed to during normal operation. Without
 
the addition of foreign chemicals the aging effects during normal operation and during
 
layup are the same.
Gland Seal Water System (37) - The system was drained (ambient air present) with the gland seal tank in component layup per MPI-1-000-TNK002. However, it was assumed
 
that the secondary containment loop seal as well as other low points in the system were
 
not completely drained. The applicant stated that therefore, stagnant treated water
 
supplied from the condensate system was evaluated for these areas.
Systems (Containment (64), Reactor Core Is olation Cooling (71), High Pressure Coolant Injection (73), and Core Spray (75) - The torus and torus attached piping for System 64 (i.e., the torus itself) and for Systems 71, 73, and 75 (torus attached piping) saw torus
 
water maintained by Chemistry Program CI-13.1, Appendix A, Table 20) for extended
 
periods of time until the torus was drained in the summer of 2003. When filled, the torus
 
is approximately half full of water with the other half ambient air. The torus water was not "flowing" in that the only significant water movement was relatively infrequent transfers
 
into and out of the Unit 1 torus. The torus on an operating unit cannot be considered "flowing" either. The operating unit's torus would also be nitrogen-inerted. Torus coating
 
touch-up/repair is part of the restart work to be completed while the torus is drained. The
 
torus impurity administrative goals for conductivi ty, chloride, and sulfate given in CI-13.1 are 2.0. &#xb5;S/cm, 75 ppb, and 75 ppb, respectively. The applicant stated that a review of
 
sampling data showed that the torus water was maintained within the chemistry
 
specifications and that sampling is performed quarterly. In respect to these systems, the
 
applicant will perform restart inspection prior to Unit 1 restart to verify the material
 
condition.
3-373 Inspections to be Performed Prior to Restart - In RAI 3.0-7 LP, dated August 23, 2004, the staff requested the following additional information on Notes 1 and 2 of Tables 2 and 4 concerning
 
inspections to be performed prior to the Unit 1 restart.
Notes 1 and 2 of Tables 2 and 4 indicate that a restart inspection will be performed prior to Unit 1 restart for certain components where additional aging effects were identified for the
 
extended shutdown. Examples include additional aging effects for copper alloy, cast iron, cast
 
iron alloy, and stainless steel components in system locations where condensation could build
 
up, and carbon and low-alloy steel in an internal environment. No descriptions of the inspections
 
were provided. The staff asked the applicant to discuss the proposed inspections, including
 
scope, method, procedure, parameters monitored and trended, detection of aging effects, and
 
acceptance criteria, in order to justify the adequacy of the inspections.
The applicant responded to RAI 3.0-7 LP by stating that Note 1 of Tables 2 and 4 identifies the potential for external general corrosion on carbon and low-alloy steel components that are normally operated at temperatures greater than 212 &deg;F. This note is applicable to the reactor
 
vessel (RV), feedwater system (03), and the heat er vents and drains system (06). External surface monitoring is performed in accordance with the Systems Monitoring Program described in the LRA Section B.2.1.39. The applicant stated that this is the same AMP proposed for
 
managing external loss of material during the period of extended operation.
The applicant also stated that Note 2 of Tables 2 and 4 identifies the potential for internal loss of material and cracking (aluminum only) that are normally exposed to either dry air or nitrogen.
 
The applicant clarified that this note is applicable to the following systems and materials:Feedwater (03)Copper Alloy Main Steam (01)Aluminum Alloy Containment Inerting (76)Carbon and Low-alloy steel    Stainless Steel Nickel Alloy Copper Alloy
 
Aluminum Alloy
 
Cast IronContainment AtmosphereCarbon and Low-alloy steelDilution (84)Stainless Steel Copper Alloy
 
Aluminum Alloy
 
Cast Iron The applicant's response to RAIs 3.0-2 LP, 3.0-3 LP, and 3.0-4 LP, by letter dated May 27, 2005, clarified that this is a restart inspection.
Management of Galvanic Corrosion - In RAI 3.0-8 LP, dated August 23, 2004, the staff requested the following additional information on management of galvanic corrosion with the
 
water chemistry and one-time inspections.
3-374 The LRA and the supplement dated February 19, 2004, are not clear regarding the management of galvanic corrosion. There is the potential for galvanic corrosion during the
 
extended outage for those systems that were maintained in wet layup, wet non-layup, or moist
 
air such that condensation and pooling could occur. The LRA and Reference 2 state that
 
galvanic corrosion is managed through use of the Chemistry Control Program and the
 
One-Time Inspection Program; however, there were differences in water chemistry during the
 
extended outage, and the One-Time Inspection Program does not cover galvanic corrosion. The
 
applicant was requested to describe how galvanic corrosion during the extended outage is
 
managed. The applicant was also requested to discuss any inspections that are planned to
 
determine the extent of galvanic corrosion during the extended outage.
In its response to RAI 3.0-8 LP, dated October 8, 2004, the applicant stated that the Chemistry Control Program implemented during the extended outage is the same program that BFN uses on the two operating units during cold shutdown conditions for refueling and maintenance
 
outages. This extended outage program would consist of CI-13.1 chemistry program controls, which would continue to be based on the EPRI BWR Water Chemistry Guidelines (TR-103515).
 
The applicant further stated that the One-Time Inspection Program utilized to verify the
 
effectiveness of the Chemistry Control Program fo r preventing loss of material will select the susceptible locations (where materials with different electrochemical potentials are in contact in
 
the presence of contaminants). Finally the applicant stated that galvanic corrosion is included in
 
the One-Time Inspection Program.
In regard to SCC, the staff found the applicant's response to RAI 3.0-5 LP to be reasonable and acceptable, because the applicant clarified that during layup the temperature of the systemsaddressed in Tables 2 and 3 was less than 140 &deg;F in a wet layup environment; therefore, crack
 
initiation and growth due to SCC is not a concern for stainless steels and nickel-based alloys. In
 
Tables 2 and 3, SCC is correctly identified as an aging effect for stainless steel during plant
 
operation at elevated temperatures and SCC is managed by various AMPs.
The staff reviewed the applicant's responses to the above RAIs and determined that additional information was required concerning the application of the One-Time Inspection Program as a
 
verification program for layup and chemistry controls. By letter dated December 16, 2004, staff
 
submitted RAI 3.0-10 LP requesting the applicant to provide additional information on one-time
 
inspections.
The staff reviewed the applicant's responses to the above RAIs and determined that additional information was required concerning the application of the One-Time Inspection Program as a
 
verification program for layup and chemistry controls.
In RAI 3.0-10 LP, dated December 16, 2004, staff stated that industry guidance on recovering plants placed in extended layups such as Brow ns Ferry specifically recommends that a surveillance and assessment program is needed to monitor the effects of outage or storage
 
conditions on nuclear power plant components, otherwise, evidence of bad layup often will not
 
even manifest itself until after a plant has returned to power. In pursuing this line of reasoning, the staff requested that the applicant clarify if one-time inspections may not be appropriate
 
where degradation is expected to occur or occur very slowly. Spec ifically, for systems not associated with the BWRVIP program, the staff wanted the applicant to justify why a one-time
 
inspection is appropriate for aging management in lieu of periodic inspections. By letter dated
 
May 27, 2005, the applicant clarified the application of periodic inspections in lieu of one-time 3-375 inspections for areas subject to concentration of contaminants during layup. Targeted periodic inspections are going to be used as compensatory actions to be performed after Unit 1 is
 
returned to operation to verify that no additional aging effects are occurring. By letter dated
 
November 16, 2005, the applicant also clarified that the compensatory actions included visual
 
and/or ultrasonic inspections to establish t he physical condition of systems and components not being replaced. The first periodic inspection will be performed prior to the end of the current
 
operating period, and the subsequent frequency will be determined based on the outcome of
 
the first periodic inspections performed.
The restart inspections can be utilized as a baseline for comparison as identified in the Unit 1 Periodic Inspection Program (SER Section 3.0.
3.3.5). Systems and portions of systems for which periodic inspections will be performed included MS, FW, RHRSW, RCW, EECW, fire
 
protection, reactor building closed cooling water, RCIC, HPCI, RHR, and CRD. The staff
 
concurred that application of targeted periodic internal visual and ultrasonic inspections of a
 
sample of susceptible locations is appropriate to manage potential latent aging effects in Unit 1
 
systems and portions of systems in layup that were not in operation during the extended outage and have not been replaced.
These staff dialogues and the ACRS interim report, dated October 19, 2005, led to the development of a new plant-specific AMP B.2.1.42, "Unit 1 Periodic Inspection Program," for
 
BFN Unit 1 components that will not be replaced before restart.3.7.1.4  MIC In RAI 3.0-3 LP, the staff requested the following additional information on MIC:
Industry documents such as EPRI NP-5106, indicate that all metals are susceptible to MIC, especially in stagnant and low flow areas, and microbes in the system should be
 
monitored by an adequate program at least every week and more often in outages. NRC
 
Inspection Report 50-259/87-45 identified damage due to MIC had already occurred in
 
the fire protection system and water samples in the demineralized water system were
 
planned. Table 2 does not identify MIC as a corrosion mechanism (for example, in the
 
RWCU and CRD systems for systems intended for wet layup with demineralized water.
 
Table 3 does not identify MIC as a corrosion mechanism for systems that had no water
 
chemistry control (wet, non-layup) during the extended outage. Similarly, Table 4 does
 
not identify MIC as a corrosion mechanism for components subject to a moist air
 
environment for extended periods of time. Provide technical justification that MIC is not
 
an aging mechanism applicable to the stagnant, low flow, and moist air portions of the
 
mechanical systems. Alternatively, describe how inspections would detect loss of
 
material caused by MIC at susceptible locations.
In its response to RAI 3.0-3 LP, by letter dated October 8, 2004, the applicant stated:
Table 2 contains Systems [Reactor Vessel and Internals (RVI), Feedwater (03), Reactor Vessel Vents and Drains (10), Reactor Recirculation (68), Reactor Water Cleanup (69)
 
and Control Rod Drive (85)] laid up with demineralized water maintained by the
 
Chemistry Program CI-13.1 and moist air from possible pooling of Chemistry Program
 
CI-13.1 controlled treated water between drain valves and double isolation valves due to
 
closure sequence, closure timing, and possible leaking past the valves. Although 3-376 portions of these systems had stagnant, low flow, and moist air environments, the Chemistry Program prevented the presence of microbes necessary to cause MIC
 
damage. A review of BFN PERs and Work Orders (WOs) (operating experience) did not
 
identify MIC as a concern in treated water.
Table 3 contains Systems [Condenser Circulating Water (27), Gland Seal Water (37), Containment (64), Reactor Core Isolation Cooling (71), High Pressure Coolant Injection
 
(73), and Core Spray (75)]. 1.MIC is identified as a concern for raw water environments regardless of flow rate in the Condenser Circulating Water System (27). 2.The laid up environment for the Gland Seal Water System (37) was treated (condensate) water and moist air from possible pooling of treated water between
 
drain or isolation valves and in the loop seals. BFN operating experience did not
 
identify MIC as a concern in treated water environments. Although there were no
 
chemistry controls placed on system 37 during layup, raw water or other MIC
 
agents were not introduced into this system. Therefore, the microbes necessary
 
for the propagation of MIC were not present in this system during layup. 3.Treated (torus) water was maintained by the Chemistry Program CI-13.1 during wet layup. The portions of Systems [Containment (64), Reactor Core Isolation
 
Cooling (71), High Pressure Coolant Injection (73), and Core Spray (75)] within
 
the BFN LR scope (torus and torus attached piping) during Unit 1 layup had a
 
treated water environment and moist air from possible pooling of treated water (torus water) between drain valves and double isolation valves due to closure
 
sequence and timing and possible leaking past the valves. Although portions of
 
these systems had stagnant, low flow, and mo ist air environments, the Chemistry Program CI-13.1 prevented the presence of microbes necessary to cause MIC
 
damage. A review of BFN PERs and WOs (operating experience) did not identify
 
MIC as a concern in treated water.
Table 4 Systems [Main Steam (01), Condensat e (02), Heater Drains and Vents (06), Containment Inerting (76), and Containment Atmosphere Dilution (84)] contained treated
 
water or nitrogen prior to Unit 1 layup. These systems were drained during layup. These
 
systems were isolated without the introduction of raw water or other MIC agents.
 
Therefore, the microbes necessary for the propagation of MIC were not present in these
 
systems during layup.
In a follow up to the general RAI 3.0-10 LP, dated December 16, 2004, the applicant was
 
requested to clarify why one-time inspections are appropriate for locations with stagnant, low
 
flow or intermittent flow where MIC is expected on the basis of industry operating experience
 
due to possibly ineffective chemistry control in these regions. The applicant was asked to
 
identify the results of any inspections performed in low flow or stagnant areas to demonstrate
 
that aging effects are not expected to occur or are expected to occur slowly. The applicant was
 
also requested to provide information on any corrosion monitoring programs for MIC, including augmented inservice inspection of susceptible areas and corrosion coupons or spool pieces.
 
Otherwise, the applicant should consider the application of periodic inspections to evaluate
 
aging effects in these areas.
3-377 In the response provided by the applicant to RAI 3.0-10 LP, the staff's concerns relevant to MIC were not addressed. The staff was concerned that various corrosion mechanisms that would not
 
be active during operation often appear during layup, as water chemistry controls may not be as
 
stringent, particularly in stagnant areas. Industry documents such as EPRI NP-5580, "Sourcebook for Microbiologically Influenced Corrosion in Nuclear Power Plants," indicate that
 
additions of corrosion inhibitors and biocides made after layup are unlikely to be effective, as
 
distribution throughout the system is limited. EPRI NP-5580 also indicates that proper attention
 
to layup is crucial to avoid MIC and during layup, microbial growth may proceed unimpeded as
 
fluid forces that remove attached organisms from pipe or vessel surfaces are absent. Staff is
 
also concerned that corrosion mechanisms that were not active during dry layup may become
 
active when the systems are wetted and returned to operation. To complete its review, the staff
 
again requested the additional information previously requested in RAI 3.0-10 LP, on
 
inspections performed or planned to determine that MIC is not a concern for systems subject to
 
conditions that promote MIC. The staff originally proposed this as URI 3.0-5 LP. The staff
 
discussed this issue with the applicant in follow-up teleconferences. The following is a
 
disposition of the resolution of the issues in the staff follow-ups and subsequent applicant
 
submittals.
By letter dated May 27, 2005, the applicant referenced the response to RAI 3.0-10 LP included in letter dated May 18, 2005, to address MIC. In the applicant's response by letter dated
 
May 18, 2005, the applicant clarified that the raw water piping is susceptible to MIC and the
 
primary method used for MIC control is routine injection of biocides. The applicant stated that
 
this treatment method has been effective in controlling MIC for in-service raw water piping. For
 
systems not in service during the extended out age the piping was inspected and evaluated. The applicant stated that the majority of the raw water piping was in a dry layup condition and has
 
been inspected and found to have adequate wall thickness, with two exceptions. As identified
 
by the applicant, the portions of the RHRSW system in the reactor building that contained
 
moisture required replacement due to inadequate wall thickness. Similarly, approximately 3,000
 
feet of large bore and small bore RCW piping requires replacement due to inadequate wall
 
thickness.
The staff reviewed the applicant's response and found the response acceptable. The applicant clarified that raw water piping susceptible to MIC during the extended outage has either been
 
replaced or inspected to verify that adequate wall thickness exists. In addition, there is
 
reasonable assurance that the mitigative programs will be effective to preclude future MIC and
 
potential latent aging effects due to MIC in all systems subject to layup during the extended
 
outage, including systems containing raw water, will be detected and corrected by future
 
periodic inspections. All issues related to RAI 3.0-5 LP are resolved.
3.7.1.5  Transition from Layup Program to System Cleanliness Verification Program The system cleanliness verification program is not addressed in the LRA nor in February 19, 2004, letter containing the attachment, "Evaluation of BFN Unit1 Layup and Preservation
 
Program." NRC quarterly integrated inspection report 05000259/2004006 states that on
 
March 22, 2004, the applicant decided to remove all Unit 1 systems from layup. This decision
 
was based on the need to transition to a system Cleanliness Verification Program. According to
 
NRC quarterly integrated inspection report 05000259/2004007, this program is intended to
 
replace the previous equipment layup program that has been in place since the unit was
 
shutdown. This report also stated that, under the new program, the assigned system and 3-378 component engineers, along with chemistry personnel, would perform a series of inspections of Unit 1 systems to identify any system degradati on or special requirements to support Unit 1 recovery. It is the staff's understanding that transition to the newer program was still in progress
 
at the time of the inspection period on July 10, 2004.
In RAI 3.0-11 LP, dated December 16, 2004, the applicant was requested to clarify if this series of inspections is part of the One-Time Inspection Program that is going to be implemented prior
 
to Unit 1 restart. If the one-time inspections are different from or in addition to the cleanliness
 
verification program inspections, the applicant was requested to so clarify. Also, it is not clear to
 
the staff if this system cleanliness verifica tion program includes inspections on components that were replaced or repaired. The applicant was requested to provide additional information as to
 
what type of inspections have been or will be per formed by the system Cleanliness Verification Program (CVP).
In its response to RAI 3.0-11 LP, the applicant stated that inspections performed under the CVP are not part of the one-time LRA inspections or credited as part of the license renewal
 
application. The applicant clarified that to facilitate Unit 1 restart activities, Unit 1 systems have
 
been removed from the layup program. It is not possible to maintain the layup program and perform the required field work needed for restart of Unit 1.
The applicant stated that the purpose of the CVP is to (1) verify, through cleanliness verification of all internal and external surfaces of piping systems and metallic components, that the
 
requirements for fluid (gas or liquid) system in ternal and external cleanliness are in accordance with TVA and industry standards; and (2) provide the detailed remedial cleaning instructions for
 
internal and external surfaces of piping sy stems and metallic components whose internal and external surface cleanliness does not meet respective cleanliness criteria as a result of
 
extended layup, or work activity.
The CVP activities are applicable to all Unit 1 steam, water, air, gas and oil piping systems and components that receive a formal return to service in accordance with the Unit 1 Restart Test
 
Program System Preoperational Checklist. The applic ant clarified that the only Unit 1 systems excluded from this program are those that are currently in service or have been in service supporting Units 2 and 3.
The applicant also stated that CVP inspections are performed to ensure internal and external system cleanliness and that foreign material control program requirements are met. Visual
 
inspections aided by boroscopes are performed to identify any needed remedial cleaning or
 
flushing activities. If inspection reveals evidence of piping degradation, a problem evaluation
 
report is initiated and entered into the Corrective Action Program. An engineering evaluation is
 
performed to ensure that the system is capable of operation through the extended period. The
 
applicant further stated that the inspections performed by the CVP are not a part of the
 
one-time LRA inspections; nor are they a part of the license renewal process.
The staff reviewed the applicant's response to RAI 3.0-11 LP and found that the response is reasonable and acceptable because the applicant provided sufficient information on system
 
cleanliness inspections and clarified that cleanliness inspections are different from the one-time
 
inspections credited for license renewal. The applicant credits visual inspections aided by
 
boroscopes to detect and correct degradation during the transition period between layup and
 
restart. Both external and internal inspections are performed to industry standards as part of the 3-379 system Cleanliness Verification Program. Internal inspections to recognized industry standards should be adequate to detect degradation during the transition period between layup and
 
restart. 3.7.2  Reactor Vessel internals and Reactor Coolant System 3.7.2.1 Reactor Recirculation System (068)
Summary of Technical Information in the Application.
The applicant provided a summary of its evaluation of the Unit 1 layup and preservation program in LRA Section 3.0.1. The applicant's specific AMRs for the reactor recirculation
 
system (068) of Unit 1 that are exposed to we t layup environment are given in Table 2 of the applicant's letter, "Evaluation of the BFN Unit 1 Lay-up and Preservation Program," Revision 1, dated February 19, 2004. The applicant identified several aging effects of the applicable
 
materials of the reactor recirculation system that are exposed to the wet layup environment.
These components extend from the reactor vessel outlet nozzle, through the valves and pumps, to the reactor vessel inlet nozzle. Also included are components within the reactor recirculation
 
motor generator set oil system and instrument tubing and piping outside the drywell.
In Section 4.0 of chapter "Mechanical Syst em/Program Evaluation Detail-Wet Layup Program Unit 1" of the February 19, 2004, letter, the applicant identified the following aging effects
 
associated with stainless steel, carbon steel, and copper-alloy materials that are exposed to a
 
treated-water environment during the wet layup period of Unit 1.
* general corrosion
* crevice corrosion
* pitting corrosion
* galvanic corrosion
* selective leaching In Table 2, "Evaluation of BFN Unit 1 Layup and Preservation Program," Revision 1, the applicant provided a summary of AMRs for the reactor recirculation systems of Unit 1 that are
 
within the boundary of the wet layup program. These AMRs are not addressed in the GALL
 
Report. The staff also identified areas where additional information or clarification was needed.
 
The staff's evaluation of the applicant's responses to those RAIs is included below.
Crevice and Pitting Corrosion. The staff, after the review of the applicant's submittal, determined that aging effects due to crevice and pitting corrosion of the reactor recirculation system, are
 
possible unless stringent control on the RCS water is implemented during the wet layup period.
 
The aging effects due to crevice and pitting corrosion on the reactor recirculation system
 
materials (i.e., carbon steel, stainless steel, and copper-alloy materials) can be more
 
pronounced when they are exposed to stagnant conditions during the wet layup rather than the
 
regular service condition. The applicant stated that the reactor recirculation system materials
 
will experience crevice and pitting corrosion w hen the dissolved oxygen content in the RCS water exceeds 100 ppb, and the choride and sulphate contents exceed and 150 ppb with
 
stagnant or low flow conditions during the wet layup period. In Table 2 of the applicant's
 
submittal, "Evaluation of the BFN Unit 1 Lay-up and Preservation Program," Revision 1, the
 
applicant claims that it will manage this aging e ffect by CI-13.1 Chemistry Control Program. The 3-380 cold shutdown impurity limits for conductivity, chloride, and sulfate given in CI-13.1 (1.5. &#xb5;S/cm, 15 ppb, 15 ppb) are more restrictive than those given in the EPRI BWR Water Chemistry
 
Guidelines (TR-103515-R2, page 4-6, Table 4-2) for "Reactor Water - Cold Shutdown." The
 
staff found that the implementation of the Chemistry Control Program would enable the
 
applicant to subsequently mitigate the crevice and pitting corrosion in the reactor recirculation
 
system components.
Selective Leaching. The staff, after the review of the applicant's submittal, determined that the aging effect due to selective leaching of reactor recirculation system components fabricated
 
from copper-alloy material used in a treated-water environment require aging management for
 
selective leaching for the period of extended operation for the Unit 1 layup systems. The applicant stated that copper-zinc alloys containing greater than 15 percent zinc in a
 
treated-water environment are susceptible to selective leaching, while copper alloys with a
 
copper content in excess of 85 percent resist dezincification. The applicant currently credits the
 
One-Time Inspection Program and the Selective Leaching of Materials Program; but, requires
 
no additional aging management of Unit 1 due to the wet layup condition as shown in Table 2 of
 
its February 19, 2004, letter. The staff found this acceptable because the One-Time Inspection
 
Program and Selective Leaching Program will be just as effective to detect and manage selective leaching on the Unit 1 wet layup systems as it is on systems not in wet layup in BFN.
Loss of Material Due to General Corrosion. General corrosion of carbon and low-alloy steel in treated water is an aging mechanism that must be managed for the period of extended
 
operation for the Unit 1 layup Systems. The applic ant identified the Chemistry Control Program,the One-Time Inspection Program and ASME Section XI Subsections IWB, IWC and IWD
 
Inspection Program. The Chemistry Control Program mitigates general corrosion by minimizing
 
dissolved oxygen, thus, reducing the effect of general corrosion as an internal aging effect. The
 
applicant's one-time inspection will ensure that general corrosion has been controlled and the ASME Section XI inspections will ensure that the affected components continue to perform their
 
required function during the period of extended operation.
Loss of Material Due to Galvanic Corrosion. Galvanic corrosion of carbon and low-alloy steel in treated water is an aging mechanism that must be managed for the period of extended
 
operation for the Unit 1 layup systems. The applic ant identified the Chemistry Control Program,the One-Time Inspection Program, and ASME Section XI Subsections IWB, IWC and IWD
 
Inspection Program. The Chemistry Control Program minimizes galvanic corrosion by controlling dissolved oxygen, chlorides, conductivity, and PH. The applicant's one-time
 
inspection will provide verification that galvanic corrosion has been managed during the Unit 1 wet layup period and the ASME Section XI inspections will ensure that the affected components
 
continue to perform their required function during the period of extended operation.
As a result of the Unit 1 restart efforts, the applicant is in the process of replacing several components and is conducting numerous inspections. Below is a description of some of the
 
restart efforts that impact the recirculation system and provide additional confidence that Unit 1
 
will be adequately managed so that the intended functions of the reactor recirculation system
 
are maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
Recirculation System Piping. During the restart efforts on Unit 1, several components will be replaced, obviating the need to be concerned about degradation of these components during 3-381 the wet-layup period. In RAI 3.1.2.4-6, dated December 1, 2004, the staff requested that the applicant discuss whether the recirculation syst em piping had experienced any cracking in the past. The applicant responded in part that no recirculation system piping welds less than NPS 4
 
were identified as having cracking or crack indications in the inservice records. The applicant
 
also stated that during the Unit 1 recovery efforts the recirculation system piping greater than
 
NPS 4 is being replaced with IGSCC-resistant piping (316NG or 316L). According to the
 
applicant, this includes all welds that it identified as having IGSCC indications. In order to clarify
 
the extent of piping replacement in the reactor recirculation system, the staff requested the
 
applicant to discuss replacement of piping less than NPS 4 in a follow up to RAI 3.1-1. The
 
applicant responded by letter dated January 20, 2005, and stated that all piping of the reactor
 
recirculation system (068) is being replaced with the exception of small sections of the 3/4-inch and 1-inch piping on each side of the system 068 penetrations on LR drawing 1-47E817-1-LR.
 
Heat Exchangers. All heat exchangers that are not being replaced due to design changes are being inspected. Inspection will include 100 percent eddy current testing of tubes. SR heat
 
exchangers will have their shell casing ultrasonically tested for thickness. The applicant also
 
stated that visual inspections of the heat exchangers for pitting or erosion are performed when
 
manway covers are removed or the connecting piping is replaced.
Valves. Valves within the piping systems were reviewed to determine whether the valves needed to be replaced or refurbished. During the Unit 1 restart effort, approximately 3000 valves
 
will be replaced. The applicant also estimated that approximately 1000 valves will be tested and
 
refurbished.
Conclusion. The staff, after reviewing the applicant's submittal, concluded that the aforementioned aging effects do not cause any additional degradation of components in the
 
reactor recirculation system during the wet layup period at Unit 1. The staff believes that the
 
relevant critical variables that may cause any additional degradation due to these aging effects
 
are adequately managed during the wet layup period. If by chance some additional degradation
 
occurred in the reactor recirculation system, the applicant's restart activities should be effective
 
in identifying and correcting issues prior to start up.
3.7.2.2  Reactor Vessel (RV), Reactor Vessel Internals (RVIs)
Summary of Technical Information in the Application.
 
The applicant's specific AMRs for the RV and RVIs at Unit 1 that are exposed to the wet layup environment are given in Table 2 of the applic ant's supplemental submittal, dated February 19, 2004, "Evaluation of the Unit 1 Layup and Preservation Program, Revision 1." The applicant
 
identified several aging effects applicable to the materials in the RV and RVIs that are exposed
 
to the wet layup environment during the extended outage.
The components in the RV and RVIs include RV attachment welds, reactor closure studs and nuts, RV heads, flanges and shells, RV nozzles and safe ends, RV penetrations, RVIs core
 
shroud and core plate, RVIs core spray lines and spargers, RVIs dry tubes and guide tubes and
 
RVIs jet pump assemblies.
3-382 In Section 4.0 of the supplemental submittal dated February 19, 2004, the applicant evaluated the following aging effects that are associated with stainless steel materials when they are
 
exposed to RCS treated-water environment during the wet layup period at Unit 1.
* pitting corrosion
* crevice corrosion
* MIC
* SCC
* thermal aging
* neutron embrittlement
* stress relaxation
* particulate fouling
 
Technical Staff Evaluation of Aging Effects In Table 2 of the supplemental submittal dated February 19, 2004, the applicant provided a summary of AMRs for the RV and RVIs at Unit 1 that are within the boundary of the wet layup
 
program. These AMRs are not addressed in the GALL Report. The staff also identified several
 
areas where additional information or clarification was needed. The staff issued RAIs to the
 
applicant regarding the wet layup issues. The staff's evaluation of the applicant's submittal and
 
its responses to the RAIs are addressed below.
Pitting and Crevice Corrosion. The staff, after the review of the applicant's submittal, determined that the aging effects due to pitting and crevice corrosion of the RCS pressure and
 
non-pressure boundary components could have been significantly affected during the wet layup
 
period, unless stringent control on the RCS water was implemented during the wet layup period.
 
The RVs and RVIs could have been subjected to more frequent stagnant conditions during the
 
wet layup period than during regular service conditions. Therefore, aging effects due to pitting
 
and crevice corrosion on the RV and RVIs materials can be more pronounced when they are
 
exposed to stagnant conditions during the wet layup period. The applicant stated that the RV
 
materials may have experienced pitting when the RCS water dissolved oxygen concentration
 
exceeded 100 ppb and the chloride or sulfate concentrations exceeded 150 ppb during the wet
 
layup period. However, crevice corrosion could have occurred when the dissolved oxygen content in the RCS water exceeded 100 ppb. In Table 2 of the submittal, the applicant stated
 
that it managed these aging effects by CI-13.1 Chemistry Program. The cold shutdown impurity limits for conductivity, chloride and sulfate given in CI-13.1 [1.5 &#xb5;S/cm), 15 ppb, 15 ppb] are
 
more restrictive than those given in the EPRI BWR Water Chemistry Guidelines (TR-103515-R2, page 4-6, Table 4-2). These guidelines are applicable for RCS water when the
 
plant is in cold shutdown condition.
In RAI 3.0-1 LP(a), the staff requested that the applicant identify the differences between the chemistry program(s) implemented in the RCS syst em during the wet layup period at Unit 1 and the chemistry program to be implemented in t he RCS system at Unit 1 during the period of extended operation.
In its response to NRC RAI 3.0-1 LP(a), by letter dated October 8, 2004, the applicant stated that the RCS water was monitored for conductivity, chloride and sulfate concentrations in
 
accordance with the requirements of CI-13.1.
The chemistry control limits implemented during the wet layup period at Unit 1 are the same as the chemistry control limits utilized by Units 2 and 3-383 3 during cold shutdown conditions for refueling and maintenance outages. The selected BFN impurity limits are consistent with the limits for cold shutdown that are contained in BWRVIP-79, "BWR Water Chemistry Guidelines," (EPRI Report TR-103515-R2, February 2000), which is consistent with the GALL AMP XI.M2, "Water Chemistry," and the Chemistry Control Program.
The chemistry program implemented during the per iod of extended operation for Unit 1 is the same program as that for Units 2 and 3 during power operation conditions.
The staff reviewed the response and found that implementation of a Chemistry Control Programthat is more restrictive than GALL AMP XI.M2, would enable the applicant to mitigate pitting
 
corrosion effectively in the RV and RVIs during the wet layup period at Unit 1.
The staff contended that if the dissolved oxygen content exceeded 100 ppb during the wet layup period, crevice corrosion of the RVIs could have occurred. In order to ensure that crevice
 
corrosion is not occurring in the RV and RVIs, the staff requests that the applicant confirm that
 
the dissolved oxygen content in the RCS water did not exceed 100 ppb during the wet layup
 
period. This staff issue was resolved by the applicant's subsequent response and submittals (see SER Section 3.7.2.2 below).
In RAI 3.0-1 LP(b), the staff requested that the applicant discuss the criteria (e.g., guidelines) used to maintain the chemistry of the fluid in the wet layup systems, the chemistry parameters monitored, and the frequency of the monitoring/trending.
In its response to RAI 3.0-1 LP(b), by letter dated October 8, 2004, the applicant stated that during the wet layup period reactor water was monitored in accordance with the requirements
 
specified in Table 5 of the CI-13.1. The impurity limits for conductivity, chloride, and sulfate
 
given in CI-13.1 were 1.5. &#xb5;S/cm, 15 ppb and 15 ppb, respectively. The applicant also stated
 
that sampling was performed once every two weeks, and the monitoring and trending results
 
demonstrated that the RCS water was maintained within its impurity limits during the wet layup
 
period. Since the verification frequency of the RCS water chemistry is once every two weeks during the wet layup period, the staff determined that pitting and crevice corrosion in the RV and RVIs can
 
occur if they are exposed to higher concentrations of chlorides and sulfates due to a leak in the
 
primary systems. The staff issued follow-up RAI 3.0-1 LP (b), requesting that the applicant
 
provide information regarding its past experience related to any sudden increase in
 
concentration of chlorides and sulfates in the RCS water during the wet layup period, and the
 
corrective actions taken to prevent impurities mi grating into crevices in the RV and RVIs. The staff further requested that the applicant identify the crevice locations in the RV and RVIs that
 
will not be replaced and where accumulation of aggressive ions such as chlorides and sulfates
 
inside the crevice could have enhanced the likelihood of pitting and crevice corrosion during the
 
wet layup period at Unit 1. The staff also requested that the applicant provide information
 
regarding the type of inspection it intends to use in identifying the aging effects due to pitting
 
and crevice corrosion in the RV and RVIs prior to Unit 1 restart and during the extended period
 
of operation.
In its response to follow-up RAI 3.0-1 LP(b), by letter dated January 31, 2005, the applicant stated that during the wet layup period at Unit 1, the RCS water was operated as a closed-loop
 
system using the RWCU system. Impurities (i.e., chlorides and sulfates) in the make-up water
 
system at Unit 1 can potentially contaminate the RCS water. Condensate water was used for 3-384 make-up water. If any impurities were detected, a new ion exchange resin would be applied to the RWCU system demineralizer. Since the RCS water would be processed approximately 1.5 times a day through the RWCU system, the applicant claimed that verification of RCS water
 
chemistry every two weeks would be adequate in detecting the impurities. The applicant found
 
no occurrences of sudden increase in concentration of impurities (i.e., chlorides and sulfates) in
 
the RCS water during the wet layup period at Unit 1. The applicant stated that the impurities
 
were maintained at acceptable levels (< 15 ppb) during the wet layup period. Based on stringent
 
chemistry control, the applicant claimed that the RV and RVIs were less susceptible to pitting
 
corrosion during the wet layup period. The applicant also proposed to perform inspections (discussed below) on the RV and RVIs prior to Unit 1 restart.
The staff reviewed the response and found it acceptable because the applicant implemented a Chemistry Control Program that is more restrictive than GALL AMP XI.M2. Since the impurities (i.e., chlorides and sulfates) in the RCS water were kept below the acceptable levels of 15 ppb, the RV and RVIs were less susceptible to pitting during the wet layup period.
In RAI 3.1-3 LP, the staff requested that the applicant provide details on any inspection plans for the RV and RVIs prior to Unit 1 restart.
In its response to RAI 3.1-3 LP, by letter dated August 23, 2004, the applicant stated that the RV and its components will be inspected in accordance with the requirements of the ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program. The RVIs will be
 
inspected in accordance with the requirements of relevant BWRVIP guidelines. The following
 
list includes the RVIs and the applicable BWRVIP reports approved by the staff (with the
 
exception of BWRVIP-76).*BWRVIP-18-----Core Spray *BWRVIP-25-----Core Plate
*BWRVIP-26-----Top Guide
*BWRVIP-27-A--Standby Liquid Control
*BWRVIP-38-----Shroud Support
*BWRVIP-41-----Jet Pump
*BWRVIP-47-----Lower Plenum (CRD, Incore)
*BWRVIP-48---- Vessel Attachment Welds
*BWRVIP-49-----Instrumentation Penetrations
*BWRVIP-76-----Core Shroud (under staff's review)
The applicant stated that the core shroud access hole covers will be examined in accordance with GE SIL 462, Revision 1. The applicant stated that the acces}}

Latest revision as of 12:22, 15 January 2025

Safety Evaluation Report Related to the License Renewal of Browns Ferry Nuclear Plant, Units 1, 2, and 3 (Tac Nos. MC1704, MC1705, MC1706)
ML060120453
Person / Time
Site: Browns Ferry  Tennessee Valley Authority icon.png
Issue date: 01/12/2006
From: Gillespie F
NRC/NRR/ADRO/DLR
To: Singer K
Tennessee Valley Authority
Diaz -Sanabria, Y, NRR/DLR/RLRA,415-1594
Shared Package
ML060110339 List:
References
TAC MC1704, TAC MC1705, TAC MC1706
Download: ML060120453 (839)
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