ML103640214
| ML103640214 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 12/29/2010 |
| From: | Becker J R Pacific Gas & Electric Co |
| To: | Office of Nuclear Reactor Regulation, Document Control Desk |
| References | |
| DCL-10-158, OL-DPR-80, OL-DPR-82 | |
| Download: ML103640214 (78) | |
Text
Pacific Gas and Electric Company December 29, 2010 PG&E Letter DCL-1 0-158 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Docket No. 50-275, OL-DPR-80 Docket No. 50-323, OL-DPR-82 Diablo Canyon Units 1 and 2 James R. Becker Diablo Canyon Power Plant Site Vice President Mail Code 104/5/601
- p. O. Box 56 Avila Beach, CA 93424 805.545.3462 Internal:
691.3462 Fax: 805.545.6445 10 CFR 54.21 (b) Annual Update to the DCPP License Renewal Application and License Renewal Application Amendment No. 34 Dear Commissioners and Staff: By letter dated November 23, 2009, Pacific Gas and Electric Company (PG&E) submitted an application to the U.S. Nuclear Regulatory Commission (NRC) for the renewal of Facility Operating Licenses DPR-80 and DPR-82, for Diablo Canyon Power Plant (DCPP) Units 1 and 2, respectively.
The application included the license renewal application (LRA), and Applicant's Environmental Report-. Operating License Renewal Stage. As required by 10 CFR 54.21 (b), each year following submittal of the LRA, an amendment to the LRA must be submitted that identifies any change to the current licensing basis (CLB) that materially affects the contents of the LRA, including the Final Safety Analysis Report (FSAR) supplement.
Enclosure 1 identifies DCPP LRA changes that are being made to: (1) reflect CLB that materially affect the LRA; and (2) reflect completed enhancements and commitments.
Enclosure 2 contains the affected LRA pages with changes shown as electronic mark-ups (deletions crossed out and insertions underlined).
The LRA update covers the period from July 1, 2009, through September 30, 2010. As a reviewer aid, all pages of the Appendix B aging management program section are provided, including unchanged pages, when there is a change on any of the pages in that section. Changes to existing commitments are contained in the changes to LRA Table A4-1 in Enclosure
- 2. A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway. Comanche Peak. Diablo. Canyon. Palo Verde. San Onofre. South Texas Project
- Wolf Creek Document Control Desk December 29, 2010 Page 2 PG&E Letter DCL-1 0-158 In PG&E Letter DCL-1 0-133, dated October 27,2010 (Accession Number ML 103050133), PG&E committed to revising LRA Chapters 2 and 3 Tables regarding the fire water storage and transfer tank intended functions.
Based on further evaluation, PG&E concluded that no additional changes to LRA Chapters 2 and 3 are required. If you have any questions regarding this response, please contact Mr. Terence L. Grebel, License Renewal Project Manager, at (805) 545-4160. I declare under penalty of perjury that the foregoing is true and correct. Executed on December 29, 2010. ker Site Vice President gwh/50362751 Enclosures ( cc: Diablo Distribution cc/enc: Elmo E. Collins, NRC Region IV Regional Administrator Nathanial B. Ferrer, NRC Project Manager, License Renewal Kimberly J. Green, NRC Project Manager, License Renewal Michael S. Peck, NRC Senior Resident Inspector Alan B. Wang, NRC Licensing Project Manager A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway. Comanche Peak. Diablo Canyon. Palo Verde. San Onofre. South Te x as Project
- Wolf Creek PG&E Letter DCL-10-158 Page 1 of 3 DCPP License Renewal Application (LRA) Changes Reflected in the Annual LRA Update Amendment 34 Affected LRA Section Reason for Change Section 2.3.3.1 Section 4.7.1
Table 4.7-1
Table A4-1, #26 Reflect the removal of the Unit 1 missile shield hoist from containment during the sixteenth refueling outage beginning
October 2010. The Unit 2 missile shield hoist was removed
during the fifteenth refueling outage beginning October 2009.
Section 4.3.2.2
Table 4.3-4
Section 4.7.2
Appendix A1.5
Appendix A3.2.1.2
Table A4-1, #28, 29
Appendix B2.1.5
Appendix B2.1.37 Update to reflect the installation of the replacement reactor vessel closure head (RRVCH) Unit 1.
All components penetrating the RRVCHs and welded to the inner
surfaces of the RRVCHs including the head vent piping and
elbows have been replaced with Alloy 690.
DCPP Unit 1 and 2 CRDM pressure housings, the core exit
thermocouple nozzle assemblies, and the thermocouple nozzles
have been replaced with the RRVCHs.
The replacement components have been qualified through the
period of extended operation.
The design codes for the original RRVCH and associated
components were deleted and Unit 1 was added to the design
codes for the RRVCH and associated components.
Table A4-1 #18
Appendix B2.1.38 Update to reflect correct U2 switchyard breakers 542/642. Table A4-1 #40, 41, 42 Calculation No. 2305C, including its acceptance criteria, was revised to be consistent with the latest revision of Procedure NDE
VT 3C-1. The acceptance criteria are now consistent with ACI
349.3R Chapter 5 detailed quantitative acceptance criteria.
Table 2.3.1-2
Section 3.1.2.1.2
Table 3.1.2-2
Table A4-1 #47 Aluminum tape that was installed on the seams of the Unit 1 RMI insulation panels of the pressurizer loop seals was removed
during the Unit 1 sixteenth refueling outage and the pressurizer
relief valves were modified to steam seats eliminating reliance on
safety related insulation. Table 3.3.2-18 DCPP Feedwater System 03 does not specify flow accelerated corrosion (FAC) AMR lines (VIII.D1-9) for susceptible feedwater
piping. Some feedwater piping is high temperature and pressure
and wall thinning/FAC is an applicable aging effect/aging
mechanism. Upon review of other systems, some components in
the 05 system were also identified which should have FAC as an
aging mechanism. Section 2.3.4.5 To provide an updated list of boundary drawings for the Auxiliary Feedwater System.
Section 3.5.2.1.14
Table 3.5.2-14 To revise aging effect for lubrite PG&E Letter DCL-10-158 Page 2 of 3 Affected LRA Section Reason for Change Table 3.4.2-1 To add an aging evaluation line for carbon steel piping in atmosphere/weather for the Main Steam System Section 3.3.2.1.14
Table 3.3.2-14 To revise priming pump material from PVC to PPS for the Diesel Generator System Table 2.3.3-5
Table 3.3.2-5
Table A4-1, #49
Appendix B2.1.13 LRA Tables 2.3.3-5 and 3.3.2-5 were revised to add the filter and pressure boundary functions to the strainers and the filter function
to the screens. LRA Appendix B2.1.13 has been updated to
reflect the PM of the strainers and screens managed by this
program.
PG&E Letter DCL-10-128 dated October 12, 2010, evaluated
components that support long term cooling for additional
component intended functions. In the letter, PG&E indicated that
other components in long term cooling paths will be evaluated to
ensure additional components and intended functions are
managed by the Fire Water Syst em Aging Management Program B2.1.13.
All components in the condensate, makeup water, and fire
protection systems that support the long term cooling function
were evaluated for additional component intended functions.
Strainers in the makeup water system that support long term
cooling and firewater inventory were identified. These strainers
are currently cleaned and inspected on a 24-month frequency
controlled by the Diablo Canyon PM program. Debris screens on
the Raw Water Storage Reservoir (RWSR) are in the flowpath
which feeds long term cooling and the firewater system. These
screens will be visually inspected on a 24-month frequency.
These PM activities will be performed as part of the Fire Water
System Aging Management Program, B2.1.13.
Section 3.5.2.2.2.7
Table 3.1.2-1
Table 3.1.2-3
Table 3.1.2-4
Table 3.5.1
Table 3.5.2.14 The responses to RAI sets 19, 21, and 25 require changes to the TLAA report and corresponding TLAA sections.
Section 2.1.2.3.5
Figure 2.1-2 Update to reflect correct 230-kV switchyard disconnects Section 2.5 Section 3.6.2.1.6
Table 3.6.1
Table 3.6.2-1 Update to include aluminum to metal enclosed bus construction material. Clarified in Table 3.6.1 that non-segregated metal
enclosed bus is consistent with NUREG-1801 and define
exceptions for Isolated Phase Bus. Table A4-1, #45, 48, 53 Aligned the Implementation Schedule with the commitment statement.
PG&E Letter DCL-10-158 Page 3 of 3 Affected LRA Section Reason for Change Table 2.3.3-15 Section 3.2.2.1.1
Table 3.2.2-1
Table 3.2.2-4
Section 3.3.2.1.2
Section 3.3.2.1.5
Table 3.3.2-2
Table 3.3.2-5
Table 3.3.2-12
Table 3.3.2-15 Update based on changes to the plant component data that was used to develop the original LRA submitted on November 23, 2009. Table A4-1 #37 Added a note to indicate the commitment was deleted in PG&E Letter DCL-10-151.
PG&E Letter DCL-10-158
Page 1 of 73 LRA Amendment 34 Affected LRA Sections, Tables, and Figures Section 2.1.2.3.5 Figure 2.1-2 Section 2.3.3.1 Section 2.3.4.5 Table 2.3.1-2 Table 2.3.3-5 Table 2.3.3-15 Section 2.5 Section 3.1.2.1.2 Table 3.1.2-1 Table 3.1.2-2 Table 3.1.2-3 Table 3.1.2-4 Section 3.2.2.1.1 Table 3.2.2-1 Table 3.2.2-4 Section 3.3.2.1.2 Section 3.3.2.1.5 Section 3.3.2.1.14 Table 3.3.2-2 Table 3.3.2-5 Table 3.3.2-12 Table 3.3.2-14 Table 3.3.2-15 Table 3.3.2-18 Table 3.4.2-1 Section 3.5.2.1.14 Section 3.5.2.2.2.7 Table 3.5.1 Table 3.5.2-14 Section 3.6.2.1.6 Table 3.6-1 Table 3.6.2-1 Section 4.3.2.2 Table 4.3-4 Section 4.7.1 Table 4.7-1 Section 4.7.2 Appendix A1.5 PG&E Letter DCL-10-158
Page 2 of 73 LRA Amendment 34 Affected LRA Sections, Tables, and Figures Appendix A3.2.1.2 Table A4-1, #18, 26, 28, 29, 37, 40, 41, 42, 45, 47, 48, 49, and 53. Appendix B2.1.5 Appendix B2.1.13 Appendix B2.1.37 Appendix B2.1.38 PG&E Letter DCL-10-158
Page 3 of 73 Section 2.1 SCOPING AND SCREENING METHODOLOGY 2.1.2.3.5 Station Blackout Criterion 10 CFR 54.4(a)(3) requires that plant SSCs within the scope of license renewal include all SSCs relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with t he regulations for SBO (10 CFR 50.63).
The NRC issued a supplemental safety evaluation report (SSER) in 1992 that concluded that PG&E's revised response to the SBO (10 CFR 50.63) for Units 1 and 2 is acceptable. The DCPP SBO analysis is discussed in FSAR Section 8.3.1.6. The SBO recovery path is identified on Figure 2.1-2 , Station Blackout Recovery Path.
The DCPP SBO analysis was performed using the guidance provided in NUMARC 87-00, Rev. 0 and the coping time (the postulated maximum SBO duration) was determined to be four hours. During an SBO event, the SBO analysis
demonstrated that the plant could be safely shutdown utilizing either Buses G or H and their normally connected EDGs (Emergency AC (EAC) sources) and, thereby, the third EDG and its Bus F were declared the Alternat e AC (AAC) source. However, during an SBO event, any of the three EDGs may be used as the AAC source. The SBO analysis
takes credit for the hydraulic interconnecti on of the auxiliary saltwater systems between Unit 1 and 2 by manually opening FCV-601.
PG&E has committed to the "10 minute AAC" opt ion, therefore a "coping assessment" is not required.
The 230 kV switchyard provides primary offsite power to each unit through the unit startup transformers 11 and 21. Startup transformers 11 and 21 are connected to the 230 kV switchyard through disconnect 211-1, 211-2
, and 21 1, 3 and 213. Disconnect s 211-1 and 21 1-2 3 are is connected to switchyard buses 1 and 2 via switchyard breaker 212 and disconnects 211, 213, 217 , and 219. Switchyard breaker 212 has a bypass disconnect 215 which is also included in the primary recovery path. The startup transformers, the overhead transmission lines, t he disconnects, the switchyard breaker and the switchyard breaker control cabl es and connections are within the scope of license renewal.
The 500 kV switchyard provides backup offsite power to each unit through the unit main transformers 1 and 2 and auxiliary transformers 12 and 22. Unit auxiliary transformer
12 is connected to the Unit 1 main transformer via the Unit 1 isophase bus. The Unit 1
main transformer connects to the 500 kV switchyard through disconnects 533 and 631
via switchyard circuit breakers 532 and 632. Unit auxiliary transformer 22 is connected
to the Unit 2 main transformer via the Unit 2 isophase bus. The Unit 2 main transformer
connects to the 500 kV switchyard through disconnects 543 and 641 via switchyard
circuit breakers 542 and 642. The unit auxiliary transformers, the unit main
transformers, the isophase buses, the overhead transmission lines, the disconnects, the
switchyard breakers and the switchyard br eaker control cables and connections are within the scope of license renewal.
PG&E Letter DCL-10-158
Page 4 of 73 Section 2.1 SCOPING AND SCREENING METHODOLOGY A position paper was created to summarize the results of a review of the SBO documentation for DCPP. The position paper identifies the SSCs credited with coping and recovering from a SBO. The SSCs identif ied in the SBO position paper were used in scoping evaluations to identify SSCs that demonstrate compliance with 10 CFR 50.63.
SSCs classified as satisfying criterion 10 CFR 54.4(a)(3) related to SBO were identified as within the scope of license renewal.
PG&E Letter DCL-10-158
Page 5 of 73 Section 2.1 SCOPING AND SCREENING METHODOLOGY Figure 2.1-2 Station Blackout Recovery Path 211 642 --L 542 Midway No 2 Line 632 532 .-T.
Midway No 3 Line 622 .-----J 623 621 521 ..J 219 230 KV Switchyard A 217 215. Y 212 '1-------213 Gates 500 KV Switchyard Main Transf 1:' 211-1 1:1211-2 LJ8in.TranSf Uint 1 Umt 2 l..A.AAJ Startup Startup No 1 Line rYYY'I Transf 11 rf"(Y' rf"(Y' Transf 21 rY'YY' Iso Phase Bus Iso Phase Bus 12 KV Startup I)" I) 12 KV Startup Auxiliary uJ.JJ Transf 12 -r' ..rr 416 KV I) I) 4.16KV ') I) BUSHrLL Bus G I I I) d),oo, 6JEDG12 Unit 1 , ') Unit 2 Startup 1-Startup Transf 11 l.A..JJJ WN Transf 22 -r'[1
+---Unit 1 Unit 2 416 KV I) Bus F I t I t I) 416KV I I Bus F uJ.JJ Auxiliary rYl Transf 22 '::" -=-I) I) 416 KV I I Bus G I) ') 4.16 KV I) 6JEDG13 I) EDG236J I) EDG216J mend)
PG&E Letter DCL-10-158
Page 6 of 73 Section 2.3 SCOPING AND SCREENING RESULTS:
MECHANICAL SYSTEMS 2.3.3.1 Cranes and Fuel Handling System System Description Cranes Overhead load handling systems provide lifti ng and maneuvering capability in various buildings and structures (e.g. auxiliary, contai nment, fuel, turbine and intake structures) on the site. These systems are composed of cranes, crane-rails hoists, elevators, monorails, and trolleys.
Crane supports are evaluated with t heir appropriate structure in Section 2.4. The following cranes, monorails and trolleys are within the scope of license renewal:
Component Name Fuel Handling Building Overhead Crane (including rails)
Fuel Handling Building Overhead Crane Trolley (including rails)
Intake Structure Gantry Crane (including rails)
Intake Structure Gantry Crane Trolley (including rails)
Building Heater Reboiler 0-1 Monorail
Motor Aux Feedwater Pump 1/2-2 Monorail
RHR Heat Exchanger 1/2-1, 1/2-2 Monorail Motor-Gen Set 1/2-1 Monorail
Motor-Gen Set 1/2-2 Monorail
Spent Fuel Area Bridge Crane (Dual Hoist) (including rails)
RHR Pump 1/2-1, 1/2-2 Monorail Hoists
CCW Pump 1/2-1, 1/
2-2, 1/2-3 Monorail Charging Pump 1/2-1, 1/2-2 Monorail
Charging Pump 1/2-3/Cont Spray Pump Monorail
Safety Injection Pump 1/2-1, 1/2-2 Monorail
Containment Polar Crane (including rails)
Containment Polar Crane Trolley (including rails)
Reactor Cavity Manipulator Crane 1/2-1 (including rails)
Reactor Cavity Manipulator Crane 1/2-1 Trolley (including rails)
Containment Dome Service Crane
Reactor Cavity Service Jib Crane
Head Stud Tensioner Monorail
Missile Shield Hoist Containment Equipment Hatch Monorail
Moisture Separator Reheater 1/2-2A Monorail
Turbine Building Bridge Crane (including rails)
Turbine Building Bridge Crane Trolley (including rails)
Monorail for Electrical Pull Box Covers BP014 Through BP020 PG&E Letter DCL-10-158
Page 7 of 73 Section 2.3 SCOPING AND SCREENING RESULTS:
MECHANICAL SYSTEMS 2.3.4.5 Auxiliary Feedwater System License Renewal Boundary Drawings The license renewal boundary drawings for t he auxiliary feedwater system are listed below:
LR-DCPP-03B
-106703-03 LR-DCPP-03B
-106703-04 LR-DCPP-03B
-107703-03 LR-DCPP-03B
-107703-04
PG&E Letter DCL-10-158
Page 8 of 73 Section 2.3 SCOPING AND SCREENING RESULTS:
MECHANICAL SYSTEMS Table 2.3.1-2 Reactor Coolant System Component Type Intended Function Insulation Insulate (Mechanical
)
PG&E Letter DCL-10-158
Page 9 of 73 Section 2.3 SCOPING AND SCREENING RESULTS:
MECHANICAL SYSTEMS Table 2.3.3-5 Makeup Water System (Continued) Component Type Intended Function Strainer Filter Leakage Boundary (spatial)
Pressure Boundary
PG&E Letter DCL-10-158
Page 10 of 73 Section 2.3 SCOPING AND SCREENING RESULTS:
MECHANICAL SYSTEMS Table 2.3.3-15 Lube Oil System Component Type Intended Function Piping Leakage Boundary (spatial)
Pressure Boundary Valve Leakage Boundary (spatial)
Pressure Boundary
PG&E Letter DCL-10-158
Page 11 of 73 Section 2.5 SCOPING AND SCREENING RESULTS:
ELECTRICAL AND INSTRUMENTATION AND CONTROLS
2.5 SCOPING
AND SCREENING RESULTS: ELECTRICAL AND INSTRUMENTATION AND CONTROL SYSTEMS The scoping and screening results for electr ical and instrument and control system components consist of a list (Table 2.5-1 , Electrical and I&C Component Groups Requiring Aging Management Review) of component types that require AMR.
Using the plant "spaces" approach, all elec trical and instrument and control components were reviewed as a group regardless of the system assigned to each component.
Bounding environmental conditions were used to evaluate the identified aging effect(s) with respect to component function(s) to det ermine the passive component groups that require AMR. This methodology is discussed in Section 2.1.3.3 and is consistent with the guidance in NEI 95-10.
The interface of electrical and instrument and control components with other types of components and the assessments of these inte rfacing components are provided in the appropriate mechanical or structural secti ons. The evaluation of electrical racks, panels, frames, cabinets, cable trays, conduit, manhole, duct banks, transmission towers and their supports is provided in the structural assessment documented in Section 2.4. The following electrical component groups were evaluated to determine the groups that require AMR: Cable Connections (metallic parts) Connectors (exposed to borated water) Fuse Holders (not part of a larger assembly) High Voltage Insulators Insulated Cable and Connections (includes the following): Electrical cables and connections not subject to 10 CFR 50.49 EQ requirements Electrical cables and connections used in instrumentation circuits not subject to 10 CFR 50.49 EQ requirements that are sensitive to reduction in conductor insulation resistance Inaccessible Medium-Voltage Elec trical Cables not subject to 10 CFR 50.49 EQ requirements Metal Enclosed Bus (includes the following):
PG&E Letter DCL-10-158
Page 12 of 73 Section 2.5 SCOPING AND SCREENING RESULTS:
ELECTRICAL AND INSTRUMENTATION AND CONTROLS o Non-segregated Phase Bus Bus bar and connections Bus enclosure Bus Insulation and insulators o Isolated Phase Bus Bus bar and connections Bus enclosure Bus insulators Switchyard Bus and Connections Terminal Blocks (not part of a larger assembly) Transmission Conductors and Connections Lightning Rods Electrical equipment subject to 10 CFR 50.49 environmental qualification (EQ) requirements Penetrations, Electrical Grounding conductors Cable Tie Wraps A license renewal boundary drawing (LR-DCPP-ELEC-502110) was created from the plant one-line diagram. The plant one-line diagr am schematically shows the portions of the plant AC electrical distribution system, including the SBO recovery path, that are included within the scope of license renewal.
PG&E Letter DCL-10-158
Page 13 of 73 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 3.1.2.1.2 Reactor Coolant System Materials The materials of construction for the r eactor coolant system component types are: Carbon Steel Insulation Fiberglass Stainless Steel Stainless Steel Cast Austenitic Environment The reactor coolant system component types are exposed to the following environments: Borated Water Leakage Closed-Cycle Cooling Water Demineralized Water Dry Gas Plant Indoor Air Reactor Coolant Treated Borated Water Aging Effects Requiring Management The following reactor coolant system aging effects require management: Cracking Loss of fracture toughness Loss of material Loss of preload Reduction of heat transfer
PG&E Letter DCL-10-158
Page 14 of 73 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging Management Evaluation -
Reactor Vessel and Internals (Continued) Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes RV Nozzle Support Pads SS Carbon Steel Plant indoor Air (Ext) Cumulative Fatigue Damage Time Limited Aging Analysis evaluated for the period of extended operation IV.A2-20 C2-10 3.1.1.01 07 C A RVI Core Barrel Assembly DF, SH SLD , SS Stainless Steel Reactor Coolant (Ext) Cumulative Fatigue Damage Time Limited Aging Analysis evaluated for the period of extended operation IV.B2-31 3.1.1.05 A RV Core Support Lugs SS Nickel Alloys Reactor Coolant (Ext) Cumulative Fatigue Damage Time Limited Aging Analysis evaluated for the period of extended operation IV.B2-31 A2-21 3.1.1.05 9 C A PG&E Letter DCL-10-158
Page 15 of 73 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-2 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging Management Evaluation - Reactor Coolant System (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes Insulation INS Insulation Fiberglass Borated Water Leakage (Ext)
None None None None F Insulation INS Stainless Steel Borated Water Leakage (Ext)
None None V.F-13 3.2.1.57 C PG&E Letter DCL-10-158
Page 16 of 73 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-3 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging Management Evaluation -
Pressurizer (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes Valve Support Bracket (Unit 2 only) SS Carbon Steel Plant Indoor Air Cumulative Fatigue Damag e Time Limited Aging Analysis evaluated for the period of extended operation III.B1.1-12 3.5.1.42 A PG&E Letter DCL-10-158
Page 17 of 73 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-4 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging Management Evaluation - Steam Generators (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes SG Feedwater Ring DF Carbon Steel Secondary Water (Ext) Cumulative Fatigue Damage Time Limited Aging Analysis evaluated for the period of extended operation IV.D1-11 3.1.1.07 C D SG Feedwater Ring DF Nickel Alloy Secondary Water (intExt) Cumulative Fatigue Damage Time Limited Aging Analysis evaluated for the period of extended operation IV.D1-21 3.1.1.06 C SG Primary Manway Covers PB Carbon Steel Borated Water Leakage (Ext) Cumulative Fatigue Damage Time Limited Aging Analysis evaluated for the period of extended operation IV.C2-10 3.1.1.07 C, 6 SG Primary Manway Covers PB Stainless Steel Reactor Coolant (extExt) Cumulative Fatigue Damage Time Limited Aging Analysis evaluated for the period of extended operation IV.D1-9 8 3.1.1.10 A C , 5 SG Secondary Manway and Handhole Covers PB Nickel Alloys Secondary Water (ext Int) Cumulative Fatigue Damage Time Limited Aging Analysis evaluated for the period of extended operation IV.D1-21 3.1.1.06 C , 4 SG Secondary Manway and Handhole Covers PB Carbon Steel Plant Indoor Air (Ext) Cumulative Fatigue Damage Time Limited Aging Analysis evaluated for the period of extended operation IV.C2-10 3.1.1.07 C, 7 SG Tubes TH HT , PB Nickel Alloy Reactor Coolant (Int) Cumulative fatigue damage Time-limited Aging Analysis evaluated for the period of extended operation IV.D1-21 4.2.2.06 A PG&E Letter DCL-10-158
Page 18 of 73 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-4 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging Management Evaluation - Steam Generators (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes SG Tubes TH HT , PB Nickel Alloy Secondary Water (Ext) Cumulative fatigue damage Time-limited Aging Analysis evaluated for the period of extended operation IV.D1-21 4.2.2.06 A 4 Component is secondary manway or handhole pads. 5 Component is the primary manway insert plates. 6 Component is the primary manway cover. 7 Component is secondary manway or handhole cover.
PG&E Letter DCL-10-158
Page 19 of 73 Section 3.2 AGING MANAGEMENT OF EGGINEERED SAFETY FEATURES 3.2.2.1.1 Safety Injection System Materials The materials of construction for the safe ty injection system component types are:
Carbon Steel
Carbon Steel with Stainless Steel Cladding
Cast Iron
Copper Alloy (> 15 percent Zinc)
Elastomer Glass Stainless Steel
Stainless Steel Cast Austenitic Environment The safety injection system components ar e exposed to the following environments:
Borated Water Leakage
Closed-Cycle Cooling Water
Demineralized Water
Dry Gas Encased in Concrete
Lubricating Oil
Plant Indoor Air
Treated Borated Water Ventilation Atmosphere Aging Effects Requiring Management The following safety injection system aging effects require management:
Cracking Hardening and loss of strength Loss of fracture toughness
PG&E Letter DCL-10-158
Page 20 of 73 Section 3.2 AGING MANAGEMENT OF EGGINEERED SAFETY FEATURES Table 3.2.2-1 Engineered Safety Features - Summary of Aging Management Evaluation - Safety Injection System (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes Expansion Joint PB Elastomer Plant Indoor Air (Ext) Hardening and loss of strength External Surfaces Monitoring Program (B2.1.20)
VII.F2-7 3.3.1.11 E Expansion Joint PB Elastomer Ventilation Atmosphere (Int)
Hardening and loss of strength Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
VII.F2-7 3.3.1.11 E PG&E Letter DCL-10-158
Page 21 of 73 Section 3.2 AGING MANAGEMENT OF EGGINEERED SAFETY FEATURES Table 3.2.2-4 Engineered Safety Features - Summary of Aging Management Evaluation - Containment HVAC System (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes Damper SS Stainless Steel Plant Indoor Air (Ext)
None None VII.J-15 3.3.1.94 A Damper SS Stainless Steel Ventilation Atmosphere (Int) None None VII.J-15 3.3.1.94 A, 8 Plant Specific Notes:
8 The component is a SS damper housing with an internal environment of ventilation atmosphere. The component is located inside containment. Operating temperature is normally well above dew point. Condensation inside the component is not expected. Therefo re, plant indoor air (uncontrolled) is used interchangeably with ventilation atmosphere (internal).
PG&E Letter DCL-10-158
Page 22 of 73 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS 3.3.2.1.2 Spent Fuel Pool Cooling System Materials The materials of construction for the spent fuel pool cooling system component types are: Carbon Steel
Carbon Steel with Stainless Steel Cladding
Elastomer
Glass Stainless Steel
Stainless Steel Cast Austenitic Environment The spent fuel pool cooling system com ponent types are exposed to the following environments:
Borated Water Leakage
Closed-Cycle Cooling Water
Demineralized Water
Encased in Concrete
Lubricating Oil Plant Indoor Air Treated Borated Water Aging Effects Requiring Management The following spent fuel pool cooling syst em aging effects require management:
Hardening and loss of strength
Loss of material
Loss of preload
Reduction of heat transfer Aging Management Programs The following aging management programs manage the aging effects for the spent fuel pool cooling system component types:
PG&E Letter DCL-10-158
Page 23 of 73 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Bolting Integrity (B2.1.7) Boric Acid Corrosion (B2.1.4) Closed-Cycle Cooling Water System (B2.1.10) External Surfaces Monitoring Program (B2.1.20) Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22) Lubricating Oil Analysis (B2.1.23)
One-Time Inspection (B2.1.16) Water Chemistry (B2.1.2)
PG&E Letter DCL-10-158
Page 24 of 73 Section 3.3AGING MANAGEMENT OF AUXILIARY SYSTEMS 3.3.2.1.5 Makeup Water System Materials The materials of construction for the makeup water system component types are:
Asbestos Cement
Carbon Steel
Carbon Steel (Galvanized)
Cast Iron
Copper Alloy
Elastomer
Stainless Steel
Stainless Steel Cast Austenitic Environment The makeup water system components are exposed to the following environments:
Atmosphere/ Weather
Buried Demineralized Water
Encased in Concrete
Lubricating Oil Plant Indoor Air Potable Water
Raw Water
Sodium Hydroxide
Sulfuric Acid Aging Effects Requiring Management The following makeup water system aging effects require management:
Hardening and loss of strength
Loss of material PG&E Letter DCL-10-158
Page 25 of 73 Section 3.3AGING MANAGEMENT OF AUXILIARY SYSTEMS Loss of material, cracking and changes in material properties Loss of preload Aging Management Programs The following aging management programs m anage the aging effects for the makeup water system component types:
Bolting Integrity (B2.1.7) Buried Piping and Tanks Inspection (B2.1.18) External Surfaces Monitoring Program (B2.1.20) Fire Water System (B2.1.13) Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22) Lubricating Oil Analysis (B2.1.23)
One-Time Inspection (B2.1.16) Selective Leaching of Materials (B2.1.17) Water Chemistry (B2.1.2)
PG&E Letter DCL-10-158
Page 26 of 73 Section 3.3AGING MANAGEMENT OF AUXILIARY SYSTEMS 3.3.2.1.14 Diesel Generator System Materials The materials of construction for the di esel generator system component types are:
Cast Iron
Copper Alloy
Ductile Iron
Glass Polyvinyl Chloride (PVC)
Polyphenylene Sulfide (PPS)
Stainless Steel
PG&E Letter DCL-10-158
Page 27 of 73 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-2 Auxiliary Systems - Summary of Aging Management Evaluation - Spent Fuel Pool Cooling System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes Piping LBS Stainless Steel Lubricating Oil (Int) Loss of Material Lubricating Oil Analysis (B2.1.23) and One-Time Inspection (B2.1.16)
VII.E1-15 3.3.1.33 B Piping LBS , PB Stainless Steel Plant Indoor Air (Ext) None None VII.J-15 3.3.1.94 A Valve LBS Stainless Steel Lubricating Oil (Int) Loss of material Lubricating Oil Analysis (B2.1.23) and One-Time Inspection (B2.1.16)
VII.E1-15 3.3.1.33 B Valve LBS Stainless Steel Plant Indoor Air (Ext) None None VII.J-15 3.3.1.94 A
PG&E Letter DCL-10-158
Page 28 of 73 Section 3.3AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-5 Auxiliary Systems - Summary of Aging Management Evaluation - Makeup Water System (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes Piping PB Stainless Steel Lubricating Oil (Int) Loss of material Lubricating Oil Analysis (B2.1.23) and One-Time Inspection (B2.1.16)
VII.C2-12 3.3.1.33 B Screen FIL Stainless Steel Raw Water (Ext)
Loss of material Fire Water System (B2.1.13) VII.G-19 3.3.1.69 B Strainer FIL , LBS, PB Stainless Steel Plant Indoor Air (Ext) None None VII.J-15 3.3.1.94 A Strainer FIL, LBS , PB Stainless Steel Raw Water (Int)
Loss of material Fire Water System (B2.1.13) VII.G-19 3.3.1.69 B Valve PB Stainless Steel Lubricating Oil (Int) Loss of material Lubricating Oil Analysis (B2.1.23) and One-Time Inspection (B2.1.16)
VII.C2-12 3.3.1.33 B PG&E Letter DCL-10-158
Page 29 of 73 Section 3.3AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-12 Auxiliary Systems - Summary of Aging Management Evaluation - Fire Protection System (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes Valve PB Cast Iron Dry Gas (Int)
None None VII.J-23 3.3.1.97 A PG&E Letter DCL-10-158
Page 30 of 73 Section 3.3AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-14 Auxiliary Systems - Summary of Aging Management Evaluation - Diesel Generator System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes Pump LBS, SIA Polyvinyl Chloride (PVC) Polyphenylene Sulfide (PPS)
Fuel Oil (Int)
None None None None F , 2 Pump LBS, SIA Polyvinyl Chloride (PVC) Polyphenylene Sulfide (PPS)
Plant Indoor Air (Ext) None None None None F , 2 Notes for Table 3.3.2-14:
Plant Specific Notes:
2 PPS is a thermoplastic and has been evaluated for ionizing radiation, ozone, UV, thermal exposure, and loss of material due to aggressive chemical attack. No aging effects are expected for this material relative to its operating environment.
PG&E Letter DCL-10-158
Page 31 of 73 Section 3.3AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-15 Auxiliary Systems - Summary of Aging Management Evaluation - Lube Oil System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes Piping LBS, PB Stainless Steel Lubricating Oil (Int) Loss of material Lubricating Oil Analysis (B2.1.23) and One-Time Inspection (B2.1.16) VII.H2-17 3.3.1.33 B Piping LBS, PB Stainless Steel Plant Indoor Air (Ext) None None VII.J-15 3.3.1.94 A Valve LBS, PB Stainless Steel Lubricating Oil (Int) Loss of material Lubricating Oil Analysis (B2.1.23) and One-Time Inspection (B2.1.16) VII.H2-17 3.3.1.33 B Valve LBS, PB Stainless Steel Plant Indoor Air (Ext) None None VII.J-15 3.3.1.94 A
PG&E Letter DCL-10-158
Page 32 of 73 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-18 Auxiliary Systems - Summary of Aging Management Evaluation - Miscellaneous Systems in scope ONLY for Criterion 10 CFR 54.4(a)(2)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes Valve LBS Carbon Steel Secondary Water (Int) Wall Thinning Flow Accelerated Corrosion (B2.1.6)
VIII.D1-9 3.4.1.29 B Valve LBS Carbon SteelSteam (Int)
Wall Thinning Flow Accelerated Corrosion (B2.1.6)
VIII.C-5 3.4.1.29 B PG&E Letter DCL-10-158
Page 33 of 73 Section 3.4 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM Table 3.4.2-1 Steam and Power Conversion System - Summary of Aging Management Evaluation - Turbine Steam Supply System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes Piping SIA, SS Carbon Steel Atmosphere/
Weather (Int)
Loss of material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)External Sur faces Monitoring Program (B2.1.20) VIII.B1-6 VIII.H-8 3.4.1.30 3.4.1.28 B PG&E Letter DCL-10-158
Page 34 of 73 Section 3.5 AGING MANAGEMENT OF CONTAINMENTS, STRUCTURES AND COMPONENT SUPPORTS 3.5.2.1.14 Supports Aging Effects Requiring Management The following supports aging effects require management:
Cracking Loss of material
Loss of material, cracking Loss of mechanical function
Reduction in concrete anchor capacity PG&E Letter DCL-10-158
Page 35 of 73 Section 3.5 AGING MANAGEMENT OF CONTAINMENTS, STRUCTURES AND COMPONENT SUPPORTS 3.5.2.2.2.7 Cumulative Fatigue Damage due to Cyclic Loading Analyses of fatigue in component support members, anchor bolts, and welds for Group B1.1, B1.2, and B1.3 component supports (for ASME III Class 1, 2, and 3
piping and components, and for Class MC BWR containment supports) are TLAAs as defined in 10 CFR 54.3 only if a CLB fatigue analysis exists.
With the exception of the Unit 2 Pressurizer Va lve Support Bracket discussed in Section 4.3.2.4, t T he review identified no TLAAs s upporting design of these components at DCPP. DCPP ASME Class 1 piping is designed to code editions and addenda before 1986, which therefore precede cycle limits fo r allowable stress in supports (see Section 4.3.2.7
). DCPP ASME Class 2 and 3 piping and components require no fatigue or cycle design analysis for thei r supports, and no other similar analysis exist for supports for those components at DCPP.
DCPP is a PWR and does not have Class MC BWR containment supports.
PG&E Letter DCL-10-158
Page 36 of 73 Section 3.5 AGING MANAGEMENT OF CONTAINMENTS, STRUCTURES AND COMPONENT SUPPORTS Table 3.5.1 Summary of Aging Management Evaluations in Chapters II and III of NUREG-1801 for Containments, Structures, and Component Supports (Continued)
Item Number Component Type Aging Effect / Mechanism Aging Management Program Further Evaluation Recommended Discussion 3.5.1.42 Groups B1.1, B1.2, and B1.3: support members: anchor bolts, welds Cumulative fatigue damage (CLB fatigue analysis exists)
TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes, TLAA Consistent with NUREG-1801. Fatigue of support members is not a TLAA as defined in 10 CFR 54.3. See further evaluation in Section 3.5.2.2.2.7.
PG&E Letter DCL-10-158
Page 37 of 73 Section 3.5 AGING MANAGEMENT OF CONTAINMENTS, STRUCTURES AND COMPONENT SUPPORTS Table 3.5.2-14 Containments, Structures, and Component Supports - Summary of Aging Management Evaluation -
Supports (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes Supports ASME 1 SS Carbon Steel Plant Indoor Air (Structural) (Ext) Cumulative Fatigue Damage Time Limited Aging Analysis evaluated for the period of extended operation III.B1.1-12 3.5.1.42 A, 1 Supports ES, SS Lubrite Plant Indoor Air (Structural) (Ext)
Loss of mechanical function Loss of material, crackingASME Section XI, Subsection IWF (B2.1.29) III.B1.2-3 3.5.1.56 A Notes for Table 3.5.2-14:
Standard Notes:
A Consistent with NUREG-1801 item for component, material, env ironment, and aging effect. AMP is consistent with NUREG-1801 AMP. B Consistent with NUREG-1801 item for component, material, env ironment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP. F Material not in NUREG-1801 for this component.
J Neither the component nor the material and env ironment combination is evaluated in NUREG-1801.
Plant Specific Notes:
None 1 TLAA is for Pressurizer Valve Support Bracket (Unit 2 only).
PG&E Letter DCL-10-158
Page 38 of 73 Section 3.6 AGING MANAGEMENT OF ELECTRICAL AND INSTRUMENTATION AND CONTROLS 3.6.2.1.6 Metal Enclosed Bus Materials The materials of construction for metal enclosed bus are: Carbon Steel Aluminum Elastomer Porcelain Various Insulation Material (Electrical) Various Metals Used for Electrical Contacts Environment Metal enclosed bus is exposed to the following environments: Atmosphere/ Weather (Ext) Plant Indoor Air Aging Effects Requiring Management The following metal enclosed bus aging effects require management: Loosening of bolted connections Loss of material Hardening and loss of strength Embrittlement, cracking, melting, discolo ration, swelling, or loss of dielectric strength leading to reduced insulation re sistance (IR); electrical failure Aging Management Programs The following aging management program manages the metal enclosed bus: Metal Enclosed Bus (B2.1.36)
PG&E Letter DCL-10-158
Page 39 of 73 Section 3.6 AGING MANAGEMENT OF ELECTRICAL AND INSTRUMENTATION AND CONTROLS Table 3.6.1 Summary of Aging Management Evaluations in Chapter VI of NUREG-1801 for Electrical Components (Continued)
Item Number Component Type Aging Effect / Mechanism Aging Management Program Further Evaluation Recommended Discussion 3.6.1.07 Metal enclosed bus -
Bus/connections Loosening of bolted connections due to thermal cycling and ohmic heating Metal Enclosed Bus (B2.1.36)No Non-Segregated Metal Enclosed Bus is c C onsistent with NUREG-1801.
Isolated Phase Bus takes exception for welded bus construction.
3.6.1.08 Metal enclosed bus - Insulation/insulators Reduced insulation resistance and electrical failure due to various physical, thermal, radiolytic, photolytic, and chemical mechanisms Metal Enclosed Bus (B2.1.36)No Non-Segregated Metal Enclosed Bus is c C onsistent with NUREG-1801.
Isolated Phase Bus takes exception for un-insulated bus bars.
PG&E Letter DCL-10-158
Page 40 of 73 Section 3.6 AGING MANAGEMENT OF ELECTRICAL AND INSTRUMENTATION AND CONTROLS Table 3.6.2-1 Electrical and Instrument and Controls - Summary of Aging Management Evaluation - Electrical Components Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.
2 Item Table 1 Item Notes Metal Enclosed Bus (Enclosure)
Weather (Ext) Loss of materialAging Management Program for Metal Enclosed Bus (B2.1.36)
None None F Metal Enclosed Bus (Enclosure)
SS Aluminum Plant Indoor Air (Ext) Loss of materialAging Management Program for Metal Enclosed Bus (B2.1.36)
None None F Notes for Table 3.6.2-1:
Standard Notes:
A Consistent with NUREG-1801 item for component, material, env ironment, and aging effect. AMP is consistent with NUREG-1801 AMP. B Consistent with NUREG-1801 item for component, material, env ironment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP. E Consistent with NUREG-1801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-spec ific aging management program. F Material not in NUREG-1801 for this component.
J Neither the component nor the material and env ironment combination is evaluated in NUREG-1801.
Plant Specific Notes:
1 The Metal Enclosed Bus program (B2.1.36) is used to manage the aging effects for all metal enclosed bus components.
PG&E Letter DCL-10-158
Page 41 of 73 Section 4 TIME-LIMITED AGING ANALYSES 4.3.2.2 Reactor Vessel Closure Heads and Associated Components Summary Description The reactor pressure boundary components associated with the reactor vessel closure head are the CRDM pressure housings, core exit thermocouple nozzle
assemblies (CETNAs), thermocouple nozzl es, and thermocouple columns. The CRDM pressure housings, the CETNAs, and the thermocouple nozzles were
replaced with the replacement reactor vessel closure head (RRVCH) in 2009 for Unit 2 and will be replaced with the RRVCH in 2010 for Unit 1.
Table 4.3-4 lists the applicable design codes for the original (Unit 1) and replacement (Unit 2) reactor vessel closure heads and associated components. Analysis The replacement reactor vessel closure heads, CRDM pressure housings, CETNAs, and thermocouple nozzles will be have been qualified for 50 years, which will extend the design lives of the RRVCHs, CRDM pressure housings, CETNAs, and thermocouple nozzles beyond the period of extended operation.
The only reactor pressure boundary component s associated with the reactor vessel closure head that will not be have not been replaced are the thermocouple columns.
These components were originally designed to a 40-year life. The fatigue analysis for the thermocouple column resulted in a maximum design CUF of 0.29. The
design CUF was multiplied by 1.5 (60/40) to determine if the CUF would exceed 1.0.
The projection assumed the full number of the design transients during the first 40 years of operation and that t he transients continue to occur at that rate during the period of extended operation. The resulting CUF for 60 years of operation is 0.435, and therefore the TLAA remains valid fo r the period of extended operation.
Disposition:
Validation, 10 CFR 54.21(c)(1)(i);
Revision, 10 CFR 54.21(c)(1)(ii)
Validation - RRVCH The Unit 1 and 2 replacement reactor vessel heads including the RRVCHs, CRDMs, CETNAs, and thermocouple nozzles will be have been analyzed for a 50-year design life, which will extend beyond the period of extended operation. Therefore the fatigue analyses for the RRVCHs, CRDMs, CETNAs, and thermocouple nozzles will
remain valid for the period of ex tended operation, in accordance with 10 CFR 54.21(c)(1)(i). Revision - Thermocouple Column with Low Design Basis Usage Factors The current fatigue analyses of the the rmocouple column demonstrate that the maximum 40-year usage factor is 0.29. If mu ltiplied by 1.5 (60/40) to account for the 60-year period of extended oper ation, these results do not exceed 0.6, providing a large margin to the code acceptance crit erion of 1.0. The analyses of these PG&E Letter DCL-10-158
Page 42 of 73 Section 4 TIME-LIMITED AGING ANALYSES components are therefore valid for the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(ii).
Table 4.3-4 Design Codes for the Origina l and Replacement Reactor Vessel Closure Head s and Associated Components Component Code Edition/Addendum Reactor Vessel Closure Head (Unit 1 original) ASME Code,Section III, Class A 1968 Edition (no Addenda) Control Rod Drive Mechanisms Pressure Housings (Unit 1 original)
ASME Code,Section III, Class A 1968 Edition (no Addenda) Core Exit Thermocouple Nozzle Assemblies (Unit 1 original)
ASME Code,Section III 1983 Edition through the Summer 1984 Addenda Thermocouple Nozzle (Unit 1 original)
ASME Code,Section III 1983 Edition thr ough the Summer 1984 Addenda Reactor Vessel Closure Head (Unit s 1 and 2 replacement) ASME Code,Section III, Class 1 2001 Edition through the 2002 and 2003 Addenda Control Rod Drive Mechanisms
Pressure Housings (Unit s 1 and 2 replacement) ASME Code,Section III, Class 1 2001 Edition through the 2002 and 2003 Addenda Core Exit Thermocouple Nozzle Assemblies (Unit s 1 and 2 replacement) ASME Code,Section III, Class 1 1989 Edition (no Addenda)(a) Thermocouple Nozzle (Unit s 1 and 2 replacement) ASME Code,Section III, Class 1 2001 Edition through the 2002 and 2003 Addenda Thermocouple Columns (Units 1 and
- 2) ASME Code,Section III 1983 Edition through the Summer 1984 Addenda
_____________
(a) Reconciled with the 2001 Edition through the 2002 and 2003 Addenda.
PG&E Letter DCL-10-158
Page 43 of 73 Section 4 TIME-LIMITED AGING ANALYSES 4.7 PLANT-SPECIFIC TIME-LIMITED AGING ANALYSES 4.7.1 Crane Load Cycle Limits Summary Description Design guidance for cranes used to handle heavy loads over structures, systems, and components important to safe ty is provided in NUREG-0612, Control of Heavy Loads at Nuclear Power Plants. Guideline 7, Article 5.1.1 of NUREG-0612 recommends compliance with Chapt er 2 of ANSI B30.2-1976, Overhead and Gantry Cranes and Crane Manufacturers Association of America Specification Number 70 (CMAA-70), Specifications for Electric Overhead Traveling Cranes for crane design.
The design criteria of CMAA-70 are based on the estimated number of load cycles (crane lifts) over the service life of the component and design to these criteria is therefore a TLAA in acco rdance with 10 CFR 54.3.
The DCPP cranes were designed to other i ndustrial standards, before publication of these documents, as discussed in DCPP FSAR Section 9.1.4.2.1 and Design Criteria Memoranda (DCMs). In t he response to NUREG-0612, DCPP compared these designs to the NUREG-0612 guidelines to demonstrate that the intent of Chapter 2-1 of ANSI B 30.2-1976 and CMAA-70 was met. The NRC concurrence is documented in Appendix A to Supplement 27 to the DCPP Safety Evaluation Report.
DCPP cranes within the scope of NUREG-0612 carry heavy loads, i.e. loads over 1,972 lb, over components required for plant shutdown or decay heat removal, or over irradiated fuel in the reactor vessel or spent fuel pool, and are controlled by the Heavy Loads Program described in FSAR Section 9.1.4.3.5. These are designated as Category 1 cranes. The DCPP Ca tegory 1 cranes that meet NUREG-0612 requirements and are within the scope of license renewal with a TLAA associated with their design are: Containment Polar Crane (one for each unit) Missile Shield Hoist (one for each unit)
Fuel Handling Area Crane Turbine Building Crane (one for each unit) Intake Structure Crane PG&E Letter DCL-10-158
Page 44 of 73 Section 4 TIME-LIMITED AGING ANALYSES Additional cranes used at DCPP are described in FSAR Section 9.1.4.2.1. These cranes are outside the scope of NUREG-0612 bec ause their loads are less than the defined threshold for heavy loads of 1,972 lb. These additional cranes are: Reactor Cavity Manipulator Crane (one for each unit) Spent Fuel Pool Bridge Crane (one for each unit) Containment Dome Service Crane (one for each unit)
Table 4.7-1 displays DCPP crane design requirements. Analysis The Category 1, Service Class F cranes built in accordance with AISE Standard No. 6 (Containment Polar, Fuel Handli ng Area, Turbine Building, and Intake Structure Cranes) were designed for more than 2,000,000 load cycles. This far
exceeds the number of lifts that any of the DCPP cranes would make over the extended life of the plant. Based on industry experience, the Spent Fuel Pool Bridge Crane 1 is the most used crane of those within the scope of license renewal.
Assuming full core offloads and subsequent reloading of the core every refueling
outage, as well as loading of fuel into casks for dry cask storage, would
conservatively result in approximately 53,000 lifts over a 60-year period. Applying a conservative safety factor of 1.25 would br ing the estimate to 66,000 lifts, only about
3.3 percent
of the 2,000,000 design cycles.
The m issile shield hoist cranes and containment dome service cranes were designed to CMAA-70 , Service Class A requirements.
The containment dome service cranes are designed to Service Class A and the missile shield hoist cranes are designed to an unspecified service class, so Service Class A is assumed.
Service Class A cranes are designed for 20,000 to 100,000 maximum rated lifts (load cycles). The total number of load cycles for 60 years are well below even the
lower edge of the range of 20,000 lifts. Assuming 120 refueling outages for an
operating period of 60 years, it would require 166 lifts each refueling outage to reach 20,000 lifts. The containment dome service cranes typically perform less than
10 lifts per outage.
The Unit 2 missile shield hoist crane was removed from containment as part of the Unit 2 r eplacement reactor vessel closure head (RR VCH) project during the 15 th refueling outage beginning in October 2009. The Unit 1 missile shield hoist crane was removed from containment as part of the Unit 1 RRVCH project during the 16 th refueling outage beginning in October 2010. Therefore, their de sign will not be applicable during the period of extended operation.
1 The Spent Fuel Pool Bridge Crane is not designed to AISE Standard No. 6. Since it is the most-limiting crane in this evaluation, its cycles are projected for 60 years only to demonstrate that t he AISE Standard No. 6 cranes will not exceed the design criterion of 2,000,000 load cycles.
PG&E Letter DCL-10-158
Page 45 of 73 Section 4 TIME-LIMITED AGING ANALYSES The Class C, Moderate Service, requirem ents of EOCI Design Specification #61 do not provide a limiting number of load cycles for the crane designed to it, i.e. the Reactor Cavity Manipulator Crane. Rat her, the specification states that the calculated static stress in the material, based on rated load, shall not exceed 20
percent of the assumed average ultimate st rength of the material. Since the design specification does not consider the effects of aging and is not dependent upon 40 years of operation, the desi gn of the Reactor Cavity Manipulator Crane is not a TLAA under 10 CFR 54.3(a)
Criteria 2 and 3.
The Westinghouse design specifications fo r the Spent Fuel Pool Bridge Crane do not provide a limiting number of load cycles.
The specifications state that the design load plus structural weight shall be 1/5 (20 percent) of the ultimate strength of the material. Since the design specification does not consider the effects of aging and is not dependent upon 40 years of operation, the des ign of the Spent Fuel Pool Bridge Crane is not a TLAA under 10 CFR 54.3(a) Criteria 2 and 3.
Disposition: Validation, 10 CFR 54.21(c)(1)(i)
All of the DCPP cranes within the scope of license renewal either have no limiting number of loading cycles, i.e. the Reactor Cavity Manipulator and Spent Fuel Pool Bridge Cranes, in which case no TLAA exists, or are designed for more load cycles
than the maximum number expected for a 60-year period of operation. The crane designs are valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).
PG&E Letter DCL-10-158
Page 46 of 73 Section 4 TIME-LIMITED AGING ANALYSES Table 4.7-1 Crane Specifications Component Name FSAR Section Design Specification Service Class Allowable Load Cycles Validity of the Allowable Lifts for 60 Years Missile Shield Hoist (one for each unit) 9.1.4.3.5 CMAA-70 A (a) 20,000 - 100,000 N/A - The Unit 2 crane was removed in 2009.
The Unit 1 crane will be removed in 2010.
_______________
(a) The missile shield hoist crane is designed to an unspe cified service class level, thus the mini mum service class level, Service Class A, is assumed PG&E Letter DCL-10-158
Page 47 of 73 Section 4 TIME-LIMITED AGING ANALYSES
4.7.2 TLAAs
Supporting Repair of Alloy 600 Materials Summary Description Both Alloy 600 base material and Alloy 82/182 weld material have exhibited susceptibility to primary water stress corrosi on cracking (PWSCC). Evaluations of these effects, or analyses in support of repairs to affected locations, can be TLAAs.
Westinghouse performed an assessment of PWSCC susceptibility for Alloy 600 components and Alloy 82/182 welds in DCPP Unit s 1 and 2. This assessment provided guidance to DCPP for inspection of these materials, but was not time-dependent and is
therefore not a TLAA. Weld overlay repai rs have only been implemented on the Unit 2 pressurizer nozzles.
Pressurizer The Unit 1 pressurizer and its nozzles and safe ends contain no Alloy 600 or Alloy 82/182 weld material.
The Unit 2 pressurizer contains Alloy 600 ma terial only as Alloy 82/182 welds attaching the surge, spray, and relief valve nozzles to the safe ends, and the safe ends to the
connecting piping. Complete Alloy 690 structural weld overlays were completed on all
of these locations during Unit 2 Refueling Outage 14 (2R14, Spring 2008) to mitigate effects of primary water stress corrosion cra cking (PWSCC) in the original Alloy 82/182 welds. The results of the inspection and repairs were reported to the NRC in letter DCL-08-039. The overlays were supported by fatigue crack growth analyses. These fatigue crack growth analyses were projec ted to the end of the period of extended operation, and are therefore va lid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).
No base-metal corrosion analyses exist for t he pressurizers, since no half-nozzle or similar repairs have exposed the base metal to reactor coolant.
Reactor Vessel There have been no mechanical stress improv ement process (MSIP), mechanical nozzle seal assembly (MNSA), half-nozzle, or weld overlay repairs to reactor vessel Alloy 600 nozzle locations. Since there have been no MSIP, MNSA, half-nozzle, or
weld overlay repairs to reactor vessel Alloy 600 nozzle locations, no TLAA exists
supporting their installation.
Alloy 600 components previously existed in the reactor vessel heads. However, the reactor vessel head replacement was perfo rmed during Unit 2 Refueling Outage 15 (2R15, October 2009) and during is scheduled for Unit 1 Refueling Outage 16 (1R16, October 2010). All components penetrating the new reactor vessel closure heads and PG&E Letter DCL-10-158
Page 48 of 73 Section 4 TIME-LIMITED AGING ANALYSES welded to the inner surfaces of the reactor vessel closure heads will be have been replaced with Alloy 690.
See Section 4.3.2.2. Steam Generators Alloy 600 components previously existed in t he steam generators, but the Unit 1 steam generators were replaced during Unit 1 Re fueling Outage 15 (1R15, Spring 2009) and the Unit 2 steam generators were replaced during Unit 2 Refueling Outage 14 (2R14, Spring 2008). Replacement steam generator s contain no Alloy 600 or Alloy 82/182 welds. See Section 4.3.2.5. Alloy 600 Program and Other Locations DCPP procedural guidance provides a comp rehensive Alloy 600 control program for materials in the RCS. Any repairs made to Alloy 600 locations, including mechanical stress improvement process, mechanical nozzl e seal assembly, half-nozzle, or weld overlay repairs, will be implemented in accor dance with this guidance. However, other than the Unit 2 pressurizer, as discuss ed above, none of the locations have yet been subject to repairs. In the absence of analyses, no TLAAs exist.
The Plant Specific Nickel-Alloy Aging M anagement Program is discussed in Section B2.1.37.
PG&E Letter DCL-10-158
Page 49 of 73 Appendix AFinal Safety Analysis Report Supplement A1.5 NICKEL-ALLOY PENETRATION NOZZLES WELDED TO THE UPPER REACTOR VESSEL CLOSURE HEADS OF PRESSURIZED WATER REACTORS The Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors progr am manages cracking due to primary water stress corrosion cracking and loss of material due to boric acid wastage in nickel-alloy vessel head penetration nozzles and includes the reactor vessel closure head, upper
vessel head penetration nozzles and associated welds. Detection of cracking is
accomplished through implementation of a combination of bare metal visual examination (external surface of head) and surface and volumetric examination (underside of head) techniques. This program was developed in response to NRC
Order EA-03-009. ASME Code Ca se N-729-1, subject to the conditions specified in 10 CFR 50.55a(g)(6)(ii)(D)(2) through(6), has superseded the requirements of NRC Order EA-03-009.
The original Unit 1 reactor pressure vessel (RPV) head is planned to be was replaced during the 16 th refueling outage beginning that began in October 2010 and the Unit 2 RPV head was replaced during the 15 th refueling outage that began beginning in October 2009.
After RP V head replacement, i I nitial and subsequent examinations will be performed in accordance with ASME Code Ca se N-729-1, subject to the conditions specified in 10 CFR 50.55a(g)(6)(ii)(D)(2) through(6).
PG&E Letter DCL-10-158
Page 50 of 73 Appendix AFinal Safety Analysis Report Supplement A3.2.1.2 Reactor Vessel Closure Heads and Associated Components The reactor pressure boundary components asso ciated with the reactor vessel closure head are the control rod drive mechanisms (CRDM) pressure housings, core exit thermocouple nozzle assemblies (CETNAs), thermocouple nozzles, and thermocouple columns. The Units 1 and 2 CRDMs pressure housings, the CETNAs, and the
thermocouple nozzles will be have been replaced with the replacement reactor vessel closure heads (RRVCHs). The RRVCHs, CRDM pressure housings, CETNA, and thermocouple nozzles will be are designed to ASME Code,Section III. The Unit 1 and 2 RRVCHs, CRDMs, CETNAs, and thermocouple nozzles will be have been analyzed for a 50-year design life, and ther efore will remain valid for t he period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).
The only reactor pressure boundar y components associated with the RRVCHs reactor vessel closure head that will were not be replaced are the thermocouple columns.
These components were designed to the ASME Code,Section III. The current fatigue analyses of the thermocouple column dem onstrate a large margin to the code acceptance criterion of 1.0. The analyses of these components are therefore valid for the period of extended operation in a ccordance with 10 CFR 54.21(c)(1)(ii).
PG&E Letter DCL-10-158
Page 51 of 73 Appendix AFinal Safety Analysis Report Supplement Table A4-1 License Renewal Commitments Item # Commitment LRA Section Implementation Schedule 18 Enhance the Transmission Conductor, Connecti ons, Insulators and Switchyard Bus and Connections program procedures to: Identify components required to support stati on blackout recovery which are in the scope of license renewal aging management. In the 230 kV switchyard, these are the components between the startup transform ers and disconnects 217 and 219. In the 500 kV switchyard these are the com ponents between the main transformers and switchyard breakers 532/632 in Unit 1 and 543/641 542/642 in Unit 2, and Include gathering and reviewing completed ma intenance and inspection results, by the plant staff, to identify adverse trends, and Identify that an engineering evaluation will be conducted when a degraded condition is detected that considers the ex tent of the condition, report ability of the event, potential root causes, probably of recurrence, and the corrective actions required.
B2.1.38 Prior to the period of extended operation 26 The missile shield hoist crane will be remov ed from containment during the replacement reactor vessel closure head (RRVCH) project. The Unit 2 RRVCH project was completed during the fifteenth refueling out age beginning October 2009 and Unit 1 RR VCH project is planned during the sixteenth ref ueling outage beginning October 2010
. Completed
4.7.1 Prior
to the period of extended operation Completed 28 The Unit 1 reactor pressure vessel (RPV) head is planned to be replaced during the 16 th refueling o utage beginning October 2010 and the Unit 2 RPV head was replaced during the 15 th refueling outage in October 2009. All components penetrating the new reactor vessel closure heads and welded to the inner surfaces of the reactor vessel closure heads includ ing the head vent piping and elbows will be replaced with Alloy 690. Completed B2.1.5 B2.1.37 4.7.2 Prior to the period of extended operation Completed 29 DCPP Unit 1 and 2 CRDM pressure housings, the core exit thermocouple nozzle assemblies (CETNAs), and the thermocouple nozzles will be repl aced with the replacement reactor vessel closure heads (RRVCHs). The Unit 2 RPV head was replaced during the fifteenth refueling outage beginning October 2009 and Unit 1 RPV head is planned to be replaced during the sixteenth refueling outage beginning October 2010. The replacement components will be qualified through the period of extended operation.Completed 4.3.2.2 Prior to the period of extended operation Completed 37 Commitment deleted in PG&E Letter DCL-10-151.
40 Calculation No. 2305C will be revised by Novem ber 1, 2010 to be consistent with the latest revision of Procedure NDE VT 3C
-1.Completed B2.1.28 Prior to the period of extended operation Completed PG&E Letter DCL-10-158
Page 52 of 73 Appendix AFinal Safety Analysis Report Supplement Table A4-1 License Renewal Commitments Item # Commitment LRA Section Implementation Schedule 41 Calculation No. 2305C acceptance criteria will b e consistent with the latest revision of Procedure NDE VT 3C
-1. Any long term planning and decisions on potential repair will be made on a case by case basis and based on revi ew of trends in the inspection findings and will be implemented via DCPP correct ive action program.
Completed B2.1.28 Prior to the period of extended operation Completed 42 Procedure NDE VT 3C-1 and Calculation No. 2305C acceptance criteria will be revised to be consistent with ACI 349.3R Chapter 5 det ailed quantitative acceptance criteria.
B2.1.28 Prior to the period of extended
operation 45 A one-time video inspection of the Unit 2 leak chase will be performed during the period of extended operation B2.1.32 Prior to During the period of extended operation 47 Aluminum tape currentl y installed on the seems of the Un it 1 RMI insulation panels of the pressurizer loop seals is currently scheduled to be removed during the Unit 1 sixteenth refueling outage (12R16) outage, October 2010.Completed 3.1.2.1.2 Prior to the period of extended op eration Completed 48 DCPP will perform 100 percent eddy current testing of one nonregenerative heat exchanger as part of the One-Time Inspection Program within ten years prior to the period of extended operation.
B2.1.16 During the 10 years P rior to the period of extended operation.
49 DCPP will update the PM basis documents for strainers and screens in the makeup water system that support long term cooling and firewater inventory to require that they are cleaned and inspected on a 24 month frequency duri ng the period of extended operation.
B2.1.13 Prior to the period of extended
operation 53 PG&E will install cathodic protection for the ASW discharge piping in contact with soil during the first 10 year interval period excavation and inspection prior to the period of extended operation.
B2.1.18 During the 10 years P p rior to the period of extended operation PG&E Letter DCL-10-158
Page 53 of 73 Appendix B AGING MANAGEMENT PROGRAMS B2.1.5 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program Description The Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors progr am manages cracking due to Primary Water Stress Corrosion Cracking (PWSCC) and loss of material due to boric acid wastage in
nickel-alloy vessel head penetration nozzles and includes the reactor vessel closure
head, upper vessel head penetration nozzles and asso ciated welds. This program was developed in response to NRC Order EA-03-009.
ASME Code Case N-729-1, subject to the conditions specified in 10 CFR 50.55 a(g)(6)(ii)(D)(2) through(6), has superseded the requirements of NRC Order EA-03-009.
Detection of cracking is accomplished through implementation of a combination of bare metal visual examination (external su rface of head) and surface and volumetric examination (underside of head) techniques.
Evidence of reactor coolant leakage may manifest itself in the form of boric acid residues on the upper head or adjacent components or in the form of corrosion products t hat result from rusting of the low-alloy steel materials used to fabricate the ve ssel. The program conducts bare metal inspections to detect leakage from PWSCC and other sources by looking for deposition of boric acid on the external surface of the reactor vessel head. These deposits can be used to help detect and identify the origin of l eaks. This examination also serves to detect leakage from other causes and sources in proximity to the top heads that may allow boric acid deposition on and subsequent corrosion of carbon steel components.
The Inservice Inspection (ISI) Program inco rporates the governing inspections required by ASME Code Case N-729-1. A plant procedure conducts reactor vessel head bare metal visual inspections consistent with ASME Code Case N-729-1. Visual examiners shall be certified to at least Level II, VT-2; personnel performing the final evaluation of bare metal head examination data shall be Level III, VT-2.
The Nickel Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program is a monitoring program that provides measures for detecting the aging effects prio r to loss of intended function, but does not prevent degradation due to aging effects.
Preventive measures for monitoring and maintaining reactor coolant water chemistry to mitigate PWSCC are consistent with the EPRI PWR Primary Water Chemistry Gui delines. The Primary Water Chemistry Program is described separately in the Water Chemistry program (B2.1.2). The Unit 1 reactor pressure vessel (RPV) head was is planned to be replaced during the 16th refueling outage beginning in Oc tober 2010 and the Unit 2 RPV head was replaced during the 15th refueling outage begi nning in October 2009. All components penetrating the new reactor vessel closure heads and welded to the inner surfaces of the reactor vessel closure heads will be are PWSCC-resistant material (Alloy 690). NDE PG&E Letter DCL-10-158
Page 54 of 73 Appendix B AGING MANAGEMENT PROGRAMS examinations listed in Table 1, Item Number s B4.30 and B4.40, of Code Case N-729-1, subject to the conditions specified in 10 CFR 50.55a(g)(6)(ii)(D)(2) through(6), will initially be performed for the new Alloy 690 nozzles for the baseline and subsequent
examinations.
DCPP is committing to replace the reactor pressure vessel head on Unit 1 prior to the period of extended operation.
NUREG-1801 Consistency The Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program is an existing program that is consistent with NUREG-1801,Section XI.M11A, Nickel-A lloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors.
Exceptions to NUREG-1801 None Enhancements None Operating Experience Based on a review of DCPP operating experi ence, the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program has effectively managed potential degradation. In response to NRC generic correspondence, several inspections were performed and no evidence of degradation
was found. A summary of inspections from the thirteenth and fourteenth refueling outages of both units are listed below.
DCPP completed Unit 1 refueling outage 1R13 in December 2005 and 1R14 in May 2007; DCPP completed Unit 2 refueling outage 2R13 in May 2006 and 2R14 in March
2008. During these refueling outages, DCPP performed bare metal visual inspections of the RPV head penetrations and visual ins pection of the RPV head surface. No evidence of reactor vessel head penetration no zzle leakage or cracking, or degradation of the RPV head was identified. DCPP also performed nonvisual nondestructive volumetric examination on all 79 reactor vessel head penetration tubes. The
examination detected no discontinuities or i ndications of boric acid leak paths, and no flaws needing disposition or corrective action were identified. DCPP also performed a visual inspection to identify potential boric acid leaks from the pressure-retaining components above the RPV head. Minor loca lized dry boric acid deposits on small valve packing glands were identified during refueling outages 2R13 and 2R14 and
corrected. No evidence of leakage was identified from the pressure-retaining components above the RPV head during refueling outages 1R13 and 1R14.
PG&E Letter DCL-10-158
Page 55 of 73 Appendix B AGING MANAGEMENT PROGRAMS The Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program, operating experience information provides objective evidence to support the conclusion that the effects of aging will be adequately managed so that the RPV head in tended function will be maintained during the period of extended operation.
The DCPP operating experience findings for this program identified no unique plant specific operating experience; therefore DCPP operating exper ience is consistent with NUREG-1801.
Conclusion The continued implementation of the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pre ssurized Water Reactors program provides reasonable assurance that aging effects will be managed such 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.
PG&E Letter DCL-10-158
Page 56 of 73 Appendix B AGING MANAGEMENT PROGRAMS B2.1.13 Fire Water System Program Description The Fire Water System program manages loss of material due to corrosion, MIC, or biofouling for water-based fire protection system
- s. Internal and external inspections and tests of fire protection equipment are perfo rmed in accordance with applicable National Fire Protection Association (NFPA) codes and standards. The fire water system is
managed by performing routine preventive ma intenance, inspections, and testing; operator rounds, performance monitoring, and reliance on the corrective action program; and system improvements to address aging and obsolescence issues.
The following are activities performed by the Fire Water System program:
Testing: A fire water system flow test is performed at least every three years in accordance with plant procedures meeting requirements of NFPA 25. Hydraulic pump curves are obtained and compared with baseline curves to determine operability. During the Fire Water System flow test, parameters directly monitored are static pressure and velocity head. The Fire Water System program conducts a water flow test through each open spray nozzle to verify that deluge systems provide fu ll coverage of the equipment it protects.
The Fire Water System program will be enhanced so sprinkler heads in service for 50
years will be replaced or repres entative samples from one or more sample areas will be tested in accordance with NFPA 25. Te st procedures will be repeated at 10-year intervals during the period of extended operation, for sprinklers that were not replaced prior to being in service for 50 years to ensure that signs of degradation, such as corrosion, are detected prior to the loss of intended function.
The Fire Water System program conducts a water flow test through each open spray nozzle of the transformer deluge system periodically to verify that each nozzle is
unobstructed. Water is flowed through the te st valves of the deluge system periodically to ensure freedom from blockage.
Fire water is flowed from the Raw Water St orage Reservoir periodically to verify the system piping is capable of delivering the design flow rate.
The portable diesel driven fire pumps are tested periodically under full load/full flow conditions.
DCPP performs a hydrostatic test of its indoor fire hoses at least every three years, while outdoor fire hoses are tested at least annually. Fire hoses that are inaccessible
during normal plant operations ar e tested every refueling outage.
PG&E Letter DCL-10-158
Page 57 of 73 Appendix B AGING MANAGEMENT PROGRAMS Inspections:
Either periodic non-intrusive volumetric ex aminations or visual inspections will be performed on firewater piping. Non-intrusive volumetric examinations would detect loss of material due to corrosion, and would confi rm wall thickness is within acceptable limits so that aging will be detected before the loss of intended function. Visual inspections would evaluate (1) wall thickness as it applies to avoidance of catastrophic failure, and
(2) the inner diameter of the piping as it app lies to the design flow of the fire protection system. The volumetric examination tec hnique employed will be one that is generally accepted in the industry, such as ultrasonic or eddy current.
The Fire Water System program performs per iodic visual inspections of main fire system piping, yard loop fire hydrants, hose reel headers, hose stations, portable diesel driven fire pump hoses, fire hoses, gaske ts, water spray headers, sprinkler system headers, water spray nozzles, and sprinkler heads to verify they are free of significant corrosion, foreign materials, biofouling, and physical damage.
DCPP performs a visual inspection of its indoor hose station gaskets once every 18 months, except hose stations in high radi ation areas and the containment buildings which are tested during refueling outages. Th is inspection ensures that the gaskets have a satisfactory fit with no defects.
DCPP performs a visual inspection and cleaning of strainers and screens in the make-up water system that support long term cooling and firewater inventory once every 24 months during the peri od of extended operation.
Fire detection instruments located in safety related power block structures, which are accessible during plant operation, are demonstr ated to be operable at least once per six months by testing and surveillance activities. For fire detection instruments located in safety related power block structures whic h are not accessible during plant operation, operability is demonstrated during each cold shutdown exceeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, unless performed in the last six months.
Flushes: The Fire Water System program performs a flush semi-annually for the yard loop and underground feeds and annually for fire hydrants. Flowing water will remove
accumulated debris and sediment which ma y impair proper valve functioning.
The Fire Water System program acceptance criteria are 1) the ability of the fire protection system to maintain required pressure, 2) no unacceptable signs of degradation, such as loss of material due to corrosion, are observed during visual assessment of internal system conditions, and
- 3) no biofouling exists in the sprinkler system that could cause blockage in the sprinkler heads.
PG&E Letter DCL-10-158
Page 58 of 73 Appendix B AGING MANAGEMENT PROGRAMS DCPP does not have permanently installed dies el driven fire pumps. DCPP has three portable diesel driven fire pumps that may be used for fire protection. The portable diesel driven fire pumps are tested quarterly to demonstrate pump operability and annually under full load/ full flow conditions. Observation of the pump during testing
demonstrates the fuel supply line is cl ear and not degraded. During the annual test, pressure is recorded and flow is calculated to ensure adverse performance trends are
detected. NUREG-1801 Consistency The Fire Water System program is an ex isting program that, following enhancement, will be consistent with exception to NUREG-1801,Section XI.M27, Fire Water System.
Exceptions to NUREG-1801 Program Elements Affected Scope of Program - Element 1 NUREG-1801 provides a program for managing carbon steel and cast iron components in fire water systems. The Fire Wate r System program also manages components made from copper alloy and stainless steel ex posed to water in the fire water system.
The fire water system includes these materi als. Visual inspections, volumetric examinations, flushes and flow tests ar e appropriate methods for managing the aging effects for these materials and ensure t he continuity of intended function. Detection of Aging Effects - Element 4 NUREG-1801 specifies annual hydrant hose hy drostatic tests. DCPP performs a hydrostatic test of its power block fire hoses every three years. DCPP has been performing hydrostatic testing of fire hoses on a 3-year frequency for over 10 years and
no degradation leading to a loss of function has occurred.
NUREG-1801 specifies annual gasket inspections. DCPP performs gasket inspections at least once every 18 months (24 months in high radiation areas). Since aging effects are typically manifested over several year s, differences in inspection and testing frequencies are insignificant. DCPP has been inspecting at an 18-month frequency for
over 10 years and no degradation leading to a loss of function has occurred.
Enhancements Prior to the period of extended oper ation, the following enhancements will be implemented in the follo wing program elements: Detection of Aging Effects - Element 4 The Fire Protection program will be enhanced so sprinkler heads in service for 50 years will be replaced or representative samples fr om one or more sample areas will be tested PG&E Letter DCL-10-158
Page 59 of 73 Appendix B AGING MANAGEMENT PROGRAMS consistent with NFPA 25, Inspection, Testing and Maintenance of Water-Based Fire Protection Systems guidance. Test procedures will be repeated at 10-year intervals during the period of extended oper ation, for sprinkler heads that were not replaced prior to being in service for 50 years, to ensure t hat signs of degradation, such as corrosion, are detected prior to the loss of intended function.
Procedures will be enhanced for either periodic, non-intrusive volumetric examinations, or visual inspections on firewater piping. N on-intrusive volumetric examinations would detect any loss of material due to corrosi on to ensure that aging effects are managed, wall thickness is within acceptable limits and degradation would be detected before the loss of intended function. Visual inspections would evaluate (1) wall thickness as it applies to avoidance of catastrophic failure, and (2) the inner diameter of the piping as it applies to the design flow of the fire prot ection system. The volumetric examination technique employed will be one that is generally accepted in the industry, such as ultrasonic or eddy current. Monitoring and Trending - Element 5 The Fire Protection procedures will be enhanced to state trending requirements.
Operating Experience Operating experience at DCPP is evaluated and implemented to effectively maintain the fire protection system. This is accomp lished by promptly i dentifying and documenting (using the Corrective Action Program) any condi tions or events that could compromise operability of fire protection components and/or structures. In addition, industry operating experience, self assessments, and independent audits provide additional input to ensure that system operabilit y is effectively maintained.
The current system health report shows corre ctive actions are being completed in a timely manner, with favorable performance tr ending. Issues which have been identified and corrected include fire hydrant and piping corrosion and leakage.
Based on a review of DCPP operation experienc e, several examples of degradation or corrosion of the Fire Water System have been identified. Examples include: (1) while performing a surveillance test procedure in 2001, a fire protection valve was found frozen in the open position. The valve provi des for maintenance isolation; therefore, with the valve frozen open, the system is still operable and able to perform its design function. It was determined that the position and housing indicators had corrosion and
cracking and were therefore replaced. (2) Du ring replacement of a valve on October 7, 2005, the piping between firewater storage t ank 0-2 and the pump house was found to be corroded to the point of requiring repair or replacement. It was subsequently decided to replace the pipe, which was co mpleted on October 19, 2005. (3) DCPP has replaced the main fire pumps, redesi gned the transformer deluge pipe, replaced transformer deluge valve assemblies, replaced se veral yard loop risers, fire hydrants, flow switches, and has replaced many system valv es as a result of internal inspections PG&E Letter DCL-10-158
Page 60 of 73 Appendix B AGING MANAGEMENT PROGRAMS and valve leak problems identified during r outine plant walkdowns and surveillances.
The DCPP operating experience findings for this program identified no unique plant specific operating experience; therefore DCPP operating exper ience is consistent with NUREG-1801.
An assessment of the DCPP Fire Protecti on Program was performed by DCPP Quality Verification in 2000. The purpose of the a ssessment was to review the program against the commitments of the Operating License C onditions for both Units 1 and 2. Overall, the assessment team found good im plementation of the fire protection defense-in-depth elements, as well as compliance with 10 CFR 50, Appendix R requirements and the approved exemptions. Both the administrat ive and configuration control processes developed to control the program were thorough, and, in general, have been successfully implemented. The automatic sprinkler and deluge systems at DCPP were in good overall condition. Some minor variances from NFPA 13 were noted during a
walkdown of the turbine building sprinkler system. However, these items were not significant and would not have affected the ab ility of the sprinkler systems to perform as designed.
DCPP Quality Verification also performs an assessment of maintenance activities for each refueling outage. The purpose of this assessment is to verify all outage work, including fire protection, is planned, prepar ed, executed, and completed in accordance with established requirements. All of t he results are documented in Maintenance Activities Assessment Reports.
In accordance with NRC Generic Letter 82-21, Technical Specifications for Fire Protection Audits , DCPP Quality Verification performs annual, biennial, and triennial fire protection audits. The purpose of these audits is to determine if the fire protection program is satisfactorily implemented. A ll of the results are documented in Fire Protection Program Audit Reports.
In 2003, 2006, and 2009, NRC triennial fire prot ection team inspections were performed to assess the DCPP Fire Protection program fo r selected risk-significant fire areas. No findings of significance were identified.
The fire water system operating experience in formation provides objective evidence to support the conclusion that the effects of aging will be adequately managed so that the component intended functions will be main tained during the period of extended operation.
Conclusion The continued implementation of the existi ng Fire Water System program provides reasonable assurance that aging effects will be managed such 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.
PG&E Letter DCL-10-158
Page 61 of 73 Appendix B AGING MANAGEMENT PROGRAMS B2.1.37 Nickel-Alloy Aging Management Program Program Description The Nickel-Alloy Aging Management program manages cracking due to primary water stress corrosion cracking (PWSCC) in reacto r coolant system (RCS) locations that contain Alloy 600. Aging management require ments for nickel-alloy penetration nozzles welded to the upper reactor vessel closure head noted in the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vesse l Closure Heads of Pressurized Water Reactors program (B2.1.5) are included in the DCPP Nickel-Alloy Aging Management Program and are repeated here for review c onvenience. The scope of the DCPP Nickel Alloy Aging Management Program consists of the following reactor coolant pressure boundary (RCPB) locations f abricated with Alloy 600:
control rod drive mechanism (CRDM) nozzles, head vent/instrument ports/spare reactor vessel head nozzles, bottom mounted instrumentation (BMI) penetrations, r eactor vessel inlet nozzle, reactor vessel outlet nozzle, and core support lug. The term Alloy 600 is used throughout this aging
management program to represent Nickel-Alloy 600 material and Nickel-Alloy 82/182 weld metal. Non-Alloy 600 nickel components (e.g. Alloy 690 or welds made of Alloy
52/152) are not included in this program but are subject to the ASME Section XI Inservice Inspection (B2.1.1) requirements.
The Nickel-Alloy Aging Management Program us es inspections, mitigation techniques, repair/replace activities and monitoring of operating experience to manage the aging of Alloy 600 at DCPP. Detection of indica tions is accomplished through a variety of examinations consistent with ASME Section XI Subsections IWB, ASME Code Case N-729-1, ASME Code Case N-722, and EPRI Report 1010087 (MRP-139) issued under NEI 03-08 protocols. Mitigation techni ques are implemented when appropriate to preemptively remove conditions that cont ribute to PWSCC. Repair/replacement activities are performed to proactively remo ve or overlay Alloy 600 material, or as a corrective measure in response to an unacceptabl e flaw in the material. Mitigation and repair/replace activities are consistent with those detailed in MRP-139. Operating experience was reviewed and is continually monitored to provide improvements and modifications to the DCPP Nickel-Allo y Aging Management Program as needed.
Aging Management Program Elements The results of an evaluation of each el ement against the 10 elements described in Appendix A of NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants are provided below. Scope of Program - Element 1 All Alloy 600 locations within the reactor c oolant system pressure boundary (RCPB) are included within the scope of this program.
Aging management requirements for nickel-alloy penetration nozzles welded to the upper reactor vessel closure head noted in the PG&E Letter DCL-10-158
Page 62 of 73 Appendix B AGING MANAGEMENT PROGRAMS Nickel-Alloy Penetration Nozzles Welded to t he Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program (B2.1.5) are included in the Nickel Alloy Aging Management Program and are r epeated here for review convenience. The term Alloy 600 will be used throughout this program to r epresent nickel-alloy 600 material and nickel-alloy 82/182 weld metal.
The Nickel Alloy Aging Management Program identifies the following RCPB Alloy 600 locations: CRDM n ozzles (61 CRDM n ozzles including weld at no zzle to v essel c ladding w eld and n ozzle to s tainless st eel h ousing) h ead v ent n ozzle, e lbow, and h orizontal p ipe including welds at n ozzle to v essel c ladding, n ozzle to e l bow, e lbow to h orizontal p ipe, and h orizontal p ipe to stainless steel s afe-end/p iping - Note: h ead v ent n ozzle includes instrument ports and spare nozzles reactor vessel inlet and outlet nozzle safe-end weld BMI penetrations (58 BMI nozzles including welds at BMI nozzle to vessel cladding and BMI nozzle to stainless steel safe-end/piping) core support lug including welds at core support lug attachment, core support lug inlay weld (Unit 1 only), and core support lug inlay tie-in weld (Unit 1 only)
DCPP steam generators have been replaced wit h steam generator s fabricated with Alloy 690 material. Aging of steam gener ator tubes is managed by the Steam Generator Tubing Integrity program (B2.1.8) and is not covered by this program.
The reactor vessel leakage monitoring tube is fabricated of Alloy 600 with Alloy 182 welds but is not within the RCS pressure boundar
- y. Therefore it is not within the scope of this program.
The Unit 1 pressurizer locations are compos ed of stainless steel and thus not in the scope of this program. An Alloy 690 full struct ural overlay was performed for each Alloy 600 location of the Unit 2 pressurizer.
Therefore the Alloy 600 welds are no longer credited as the pressure boundary.
The Unit 1 reactor pressure vessel (RPV) head is plann ed to be was replaced during the 16th refueling outage beginning October 2010 and the Unit 2 RPV head was replaced during the 15th refueling outage in October 2009. All components penetrating the new reactor vessel closure heads and welded to t he inner surfaces of the reactor vessel closure heads including the head vent piping and elbows wil l be have been replaced with Alloy 690.
Non-Alloy 600 nickel components (e.g. Alloy 690 or welds made of Alloy 52/152) are not included in this program but are subject to the ASME Section XI Inservice Inspection (B2.1.1) requirements.
PG&E Letter DCL-10-158
Page 63 of 73 Appendix B AGING MANAGEMENT PROGRAMS Preventive Actions - Element 2 The Nickel-Alloy Aging Management Program has many potential mitigation strategies that remove one or more of the three c onditions that control primary water stress corrosion cracking (susceptible material, t ensile stress field, supporting environment).
Mitigation activities that have been successf ully performed for at least one US PWR plant include weld overlays, replacement of Alloy 600 (as a pre-planned activity), and mechanical stress improvement process (MSIP).
Full structural weld overlays may be used either as a mitigation strategy or as a repair method. This method provides structural reinforcement at the (potentia lly) flawed location, such that adequate load-carrying capability is provided by the overlay.
Components that have full structural weld overlays comprised of Alloy 690 are considered to be Alloy 690 and no longer in the
DCPP Nickel-Alloy Aging Management Program.
MSIP is a mechanical process that places the component surface in contact with the primary water in a compressive state, thereby removing the tensile stre sses needed for initiation of PWSCC.
Specific mitigation strategies will be determi ned by plant-specific and industry operating experience. The Water Chemistry program (B2.1.2) provides preventive actions for monitoring and control of the s upporting environment for PWSCC. Parameters Monitored/Inspected - Element 3 The Nickel-Alloy Aging Management Program monitors for cracking due to PWSCC.
Loss of material due to boric acid wastage is also used as an indication of cracking due to PWSCC.
For the reactor vessel upper head examinations, t T he DCPP Nickel-Alloy Aging Management Program will utilize bare metal visual, surface, and volumetric examination techniques for early detection of PWSCC in Alloy 600 components. Visual exams are employed to detect evidence of l eakage from pressure retaining components within the RCS due to cracking and/or disconti nuities and imperfections on the surface of the component. Volumetric exam ination indicates the presence of cracking/discontinuities throughout the volume of material.
The DCPP Inservice Inspection (ISI) Program and Plan will provide visual, surface, and volumetric examinations to support the Nickel-Alloy Aging Management Program. Detection of Aging Effects - Element 4 The Nickel-Alloy Aging Management Program utilizes various visual, surface, and volumetric examination techniques for early detection of PWSCC in Alloy 600
components: 1. VT-2 examinations, governed by ASM E Section XI, section IWA-5000, are conducted to detect evidence of leakage from pressure retaining components
within the RCS. 2. Bare metal visual (BMV) examinati ons, similar to VT-2 examinations, are conducted to detect evidence of leakage from pressure retaining components PG&E Letter DCL-10-158
Page 64 of 73 Appendix B AGING MANAGEMENT PROGRAMS within the RCS. Unlike VT-2 examinations, removal of insulation is required for BMV examinations to allow direct access to the bare metal surface. 3. Surface and volumetric examinations i ndicate the presence of discontinuities throughout the volume of material. DC PP uses ultrasonic testing (UT) for volumetric examinations.
The ISI Program and Plan provides visual, su rface, and volumetric examinations to support the Nickel-Alloy Aging Management Pr ogram for the components identified in Element 1.
Control Rod Drive Mechanism and Head Vents BMV, surface, and volumetric examinations are implem ented consistent with the requirements of Table 1, item s B4.30 and B4.40 B4.10 in ASME Code Case N-729-1, subject to the conditions specified in 10 CFR 50.55a(g)(6)(ii)(D)(2) through (6).
Bottom Mounted Instrument Penetrations, Reac tor Vessel Inlet & Reactor Vessel Outlet Nozzle BMV examinations are implem ented consistent with appropria te requirements of Table 1, item B15.80 in ASME Code Case N-722 subject to the conditions listed in 10 CFR 50.55a(g)(6)(ii)(E)(2) through (4).
Core Support Lugs VT-2 visual examinations are conducted in accordance with the Inservice Inspection (ISI) Program Plan. Monitoring and Trending - Element 5 Control Rod Drive Mechanism and Head Vents BMV examination frequencies for Reactor Vessel Upper Head Inspections are identified by the Nickel
-Alloy Aging Management Program for Alloy 600 locations and are consistent with the requirements of Table 1, Item B4.30 and B4.40 , in ASME Code Case N-729-1. Volumetric and Surface examination s will be implemented in accordance frequencies are consistent with appropriate requirements of Table 1, item B4.
20 40 in ASME Code Case N-729-1, subject to the conditions specified in 10 CFR 50.55a(g)(6)(ii)(D)(2) through (6).
Bottom Mounted Instrument Penetrations, Reactor Vessel Inlet and Reactor Vessel Outlet Nozzle BMV examination frequencies for BMI penetrati ons are identified by the Nickel-Alloy Aging Management Program for Alloy 600 lo cations and are consistent with ASME Code Case N-722. Examinations will be im plemented in accordance with appropriate requirements of Table 1 in ASME Code Case N-722 subject to the conditions listed in PG&E Letter DCL-10-158
Page 65 of 73 Appendix B AGING MANAGEMENT PROGRAMS 10 CFR 50.55a(g)(6)(ii)(E)(2) through (4).
Examination frequencies for reactor vessel inlet and outlet nozzles identified by the Nickel-Alloy Aging Management Program are consistent with ASME Code Case N-722, Table 1, item B15.90 (outlet nozzle) and item B15.95 (inlet nozzle).
Core Support Lug The core support lug VT-2 examination frequen cy is in accordance with the ISI Program Plan. Due to the repair/replace strategy implement ed for indications/cracking, trending is not performed in the Nickel-Allo y Aging Management Program. Acceptance Criteria - Element 6 Evaluations and acceptance criteria are in accordance with industry standards (e.g., ASME Code) or meet the acceptance of the NRC. For components included in EPRI 1010087 (MRP-139), as listed in the Nicke l-Alloy Aging Management Program, it requires that all indications found during inspections must be evaluated per ASME Section XI requirements.
Control Rod Drive Mechanism and Head Vents Relevant flaw indications detected as a resu lt of bare metal visual examinations are evaluated in accordance with acceptable flaw evaluation criteria provided in ASME Code Case N-729-1, Section 3140.
Relevant flaw indications detected as a resu lt of volumetric and surface examinations will be evaluated in accordance with acceptable flaw evaluation criteria provided in ASME Code Case N-729-1, Section 3130.
Bottom Mounted Instrument Penetrations, Reactor Vessel Inlet and Reactor Vessel Outlet Nozzle For BMI penetrations relevant flaw indications detected as a result of BMV examinations are evaluated in accordance with acceptabl e flaw evaluation criteria (IWB-3522) provided in ASME Code CaseN-722, subj ect to the conditions listed in 10 CFR 50.55a(g)(6)(ii)(E)(2) through (4).
For reactor vessel inlet and outlet nozzles relev ant flaw indications detected as a result of BMV examinations will be evaluated in a ccordance with acceptable flaw evaluation criteria (IWB-3522) provided in ASME Code Ca se N-722, subject to the conditions listed in 10 CFR 50.55a(g)(6)(ii)(E)(2) through (4). Corrective Actions - Element 7 Relevant indications failing to meet applic able acceptance criter ia are repaired or evaluated in accordance with plant procedures. Appropriate codes and standards are PG&E Letter DCL-10-158
Page 66 of 73 Appendix B AGING MANAGEMENT PROGRAMS specified in the plant ASME Section XI Repair/Replacement Program and Implementation procedure and des ign drawings. Quality assurance requirements for repair and replacement activities ar e also included in plant procedures.
A self assessment of the Nickel-Allo y Aging Management Program is conducted following two outages on each unit (approx imately every three years).
The self assessment includes a review of pertinent industry operating experience (inspection results and any leakage or cracking found in the industry), NDE technique
and tooling improvements, devel opment of new mitigation techniques, status of planned mitigation or replacement projects, lessons learned and regulatory changes.
DCPP QA procedures, review and approval proc esses, and administrative controls are implemented in accordance with the require ments of 10 CFR 50, Appendix B that are acceptable in addressing corrective actions.
The QA program includes elements of corrective action, confirmation process and adm inistrative controls and is applicable to the safety-related and nonsafety-related syst ems, structures and components (SSCs) that are subject to aging management review. Confirmation Process - Element 8 DCPP site QA procedures, review and appr oval processes are implemented in accordance with the requirements of 10 CFR 50, Appendix B and include confirmation processes as described in DCPP FSAR Section 17.2 and provisions that specify when follow-up actions are required to be taken to ve rify that corrective actions are effective and those implemented to address significant c onditions adverse to quality, are effective in preventing recurrence of the condition. Administrative Controls
- Element 9 DCPP site QA procedures, review and appr oval processes are implemented in accordance with the requirements of 10 CF R 50, Appendix B and include administrative controls as described in DCPP FSAR Section 17.2 and provisions that specify when follow-up actions are required to be taken to ve rify that corrective actions are effective and those implemented to address significant c onditions adverse to quality, are effective in preventing recurrence of the condition. Operating Experience -- Element 10 Operating experience at DCPP is evaluated and implemented to ensure that the Nickel-Alloy Aging Management Program maintains its primary goal of ensuri ng the integrity of the RCS pressure boundary. This is accomplished by promptly identifying and documenting (using the corrective action pr ogram) any conditions or events that suggest Alloy 600 degradation. In addition, industry operating experience, self assessments, and independent audits provide addi tional assurance that the program remains effective.
PG&E Letter DCL-10-158
Page 67 of 73 Appendix B AGING MANAGEMENT PROGRAMS PG&E has responded to the various NRC and industry publications on Nickel-Alloy aging issues, including NRC Generic Letter 97-01, NRC Information Notice 2000-17, NRC Information Notice 2001-05, NRC Bulletin 2001-01, NRC Bulletin 2002-01, NRC
Bulletin 2002-02, NRC Bulletin 2003-2 and NRC Bulletin 2003-11.
DCPP has proactively replaced Alloy 600 material with PWSCC resistant Alloy 690 material. The Unit 1 steam generators c ontaining Alloy 600 were replaced in 1R15 (February 2009) and the Unit 2 steam generators containing Alloy 600 were replaced in 2R14 (February 2008). The replacement steam generators were fabricated with Alloy 690 material. For the Unit 2 pressurizer, an Alloy 690 full structural weld overlay was performed for each Alloy 600 location during refueling outage 2R14 (February 2008).
The Unit 2 reactor vessel head was replac ed during 2R15 (October 2009) and the Unit 1 reactor vessel head replacement was replaced during is scheduled for 1R16 (October 2010). All components penetrating the new reactor vessel closure heads and welded to the inner surfaces of the reactor vessel closure heads will be have been replaced with Alloy 690.
Based on a review of DCPP operating exper ience, the Nickel-Alloy Aging Management Program has been effective in ensuring that the RCS will continue to operate within its licensing basis. The only leaks were four leaks on stainless steel CRDM canopy seal
welds (two on each unit). These leaks were identified during reactor vessel top and bottom head inspections. The leaks were repaired. These findings, coupled with the aggressive Alloy 600 replacement with PWS CC resistant Alloy 690, provide reasonable assurance that the systems, structures and components containing Nickel-Alloy at DCPP will continue to perform their intended function during the period of extended operation.
Enhancements None Conclusion The continued implementation of the Nickel-Alloy Aging M anagement Program provides reasonable assurance that aging effect s will be managed such that the systems, structures 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.
PG&E Letter DCL-10-158
Page 68 of 73 Appendix B AGING MANAGEMENT PROGRAMS B2.1.38 Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections Program Description The scope of the Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program includes the 230 kV and 500 kV components required for station blackout reco very. The 230 kV components include the overhead transmission conductors and connections from the unit startup transformers to
disconnects 217 and 219, the 230 kV high voltage insulators, and the switchyard bus
and connections between disconnects 217 and 219. The 500 kV components include
the overhead transmission conductors and connections from the main transformers to
disconnects 533/631 and 543/641, the 500 kV high voltage insulators, and the
switchyard bus and connections 533/631 and 543/641 and switchyard breakers 532/632 and 542/642.
PG&E has an existing preventive maint enance program that governs overhead transmission systems. This program is in accordance with the State of California General Order 95, to ensure public safety and re liability. This program requires that all 230 kV and 500 kV transmission lines be inspec ted by performance of aerial, ground and climbing inspections at specified frequencies.
The inspections look for, but are not limited to, insulator, conductor, connecto r and support degradation including corrosion, mechanical wear, and contamination. Conductors are also monitored for indications of conductor degradation including conductor strand breakage, excessive corrosion and
swelling. These inspections are docum ented, evaluated and trended. Corrective actions for abnormal conditions and failures are performed in accordance with a priority
code that is based on the observed condition and its potential to result in failure.
Inspection documentation includes who perform ed the inspection, date, findings of the inspection and recommended maintenance activities. These observed conditions may
result in follow-up inspections such as infrared thermography inspections. The
components inspected during these inspections include transmission line towers, conductors, connectors, splices and insulators. This program manages degradation of
insulator quality due to contamination, loss of transmission line strength and wear.
Prior to the period of extended operation, this existing program will be enhanced by issuance of a DCPP plant procedure to defi ne scope, responsibilities, and inspection activities for the Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program withi n the scope of license renewal. This procedure will describe the program, objectives, and requirements to manage transmission conductors and connections, insulators, and switchyard bus and
connections. The inspections look for, but are not limited to, insulator, conductor, connector and support degradation including corrosion, mechanical wear, and
contamination. Conductors are also moni tored for indications of conductor degradation including conductor strand breakage, excessive corrosion and swelling. The condition of inspected equipment is evaluated for acceptability.
PG&E Letter DCL-10-158
Page 69 of 73 Appendix B AGING MANAGEMENT PROGRAMS This program considers the technica l information provided in EPRI 1001997, Parameters that Influence the Aging and Degradation of Overhead Conductors. Aging Management Program Elements The results of an evaluation of each el ement against the 10 elements described in Appendix A of NUREG-1800, Standard Review Plan for License Renewal Applications for Nuclear Power Plants , are provided below. Scope of Program - Element 1 The scope of the Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program includes the 230 kV and 500 kV components required for station blackout recovery.
The 230 kV components include the overhead transmission conductors and connections from the startup transformers to disconnects 217 and 219, the 230 kV high voltage insulators, and the switchyard bus and connections between disconnects 217
and 219. The 500 kV components include the overhead transmission conductors and connections from the main transformers to disconnects 533/631 and 543/641, the 500
kV high voltage insulators, and the switchyard bus and connections between
disconnects 533/631 and 543/641 and switchya rd breakers 532/632 and 542/642.
Enhancements Prior to the period of extended operation plant procedures will be enhanced to identify components required to support station black out recovery which are in the scope of license renewal aging management. In t he 230 kV switchyard, these are the components between the startup transforme rs and disconnects 217 and 219. In the 500 kV switchyard these are the com ponents between the main transformers and switchyard breakers 532/632 in Unit 1 and 543/641 542/642 in Unit 2. Preventive Actions - Element 2 The Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program does not prevent degradation due to aging effects but provides measures for monitori ng to detect the degradation prior to loss of intended function. Parameters Monitored or Inspected - Element 3 The Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program is a condition monitoring program. It considers the technical information and guidance in EPRI 1001997, Parameters that Influence the Aging and Degradation of Overhead Conductors , and EPRI TR-1013475, Plant Support Engineering: License Renewal Electrical Handbook.
PG&E Letter DCL-10-158
Page 70 of 73 Appendix B AGING MANAGEMENT PROGRAMS The program will monitor high voltage insula tors, and their supports for evidence of contamination, corrosion, and wear.
Aluminum buses are inspected for degradation of the bus due to aging that would be evidenced by corrosion buildup or cracks at joints and connections.
Connections are inspected for indication of degraded or degrading connections in the affected or parallel conductor.
Conductors and their supports at Diablo Canyon will be inspected at connections and support points for broken strands and wear. Detection of Aging Effects - Element 4 Transmission conductors, insulators, connections and supports, switchyard bus and connections, and insulators within the sc ope of this program undergo annual overhead or ground based visual and infrared thermography inspections of the components. The inspections will be conducted as specified in the Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program. The
inspections look for, but are not limited to, insulator, conductor, connector and support
degradation including corrosion, mechanical wear , loss of preload, and contamination.
Conductors are also monitored for indi cations of conductor degradation including conductor strand breakage, excessive corrosion and swelling. Detailed climbing
inspections of insulators, conductors and connections will be conducted prior to the
period of extended operation. The frequency of subsequent climbing inspections will be based on the results of the initial inspecti on. Inspection results are summarized for consistent engineering criter ia evaluation of degraded conditions such as insulator contamination and switchyard bus corrosion, or mechanical wear. Corrective actions will be based on the observed degradation and will be as specified in plant procedures.
These are adequate inspection periods to detect aging effects before a loss of component intended function since experienc e has shown that aging degradation is a slow process. The first inspection for licens e renewal is to be completed prior to the period of extended operation. These frequencie s will provide multiple data points during a 20-year period, which can be used to characterize the degradation rate. Monitoring and Trending - Element 5 Monitoring of high voltage insulators, conductors, and supports for contamination, corrosion and wear or switchyard buses for corrosion and degraded connections can
aid in establishing rates of degradation to ensure corrective actions prior to loss of intended function.
Visual inspection techniques and infrared thermography inspection on an annual frequency are appropriate based on industry exper ience. The trending of results from inspection to inspection will provide a basis for timely corrective action prior to loss of
intended function.
PG&E Letter DCL-10-158
Page 71 of 73 Appendix B AGING MANAGEMENT PROGRAMS Infrared thermography inspection of connecti ons provides the capability to identify increased resistance and loss of preload in the connection. Early identification provides for timely corrective actions prior to loss of function.
Enhancements Prior to the period of extended operati on plant procedures will be enhanced to include gathering and reviewing completed maintenanc e and inspection results, by the plant staff, to identify adverse trends. Acceptance Criteria - Element 6 Visual inspections for contamination of in sulators and corrosion of switchyard bus and transmission conductors will result in consistent qualitative criteria for identifying, over time, any degradation due to aging. Corrective actions will be based on the observed
degradation and will be as specified in plant proc edures. The results of the inspections will be documented providing the ability to pr edict extent of future degradation.
Connection increased resistance, detected by infrared thermography inspection, could be evidence of connector corrosion, degradation, or loss of preload. Acceptance criteria will be based on temperature rise above a refe rence temperature. The reference temperature will be ambient tem perature or a baseline temp erature based on data from the same type of connection being tested.
Cracking of bus welds or broken cable st rands will be evaluated by engineering. The evaluation will consider the ext ent of the condition, report ability of the event, potential root causes, probability of recurrenc e, and corrective actions required. Corrective Actions - Element 7 An engineering evaluation of the results of the inspections will be conducted as specified in plant procedures when evidence of aging as described above is found. The evaluation considers the extent of condition, reportability of the event, potential root causes, the probability of recurrence, and the corrective action required. Comparison to previous inspection results for contaminati on, corrosion, and wear will aid in identifying degradation. Corrective actions will be perfo rmed in accordance with plant procedures and may include, but are not limited to in creased inspection/hot wash frequency, replacement or repair. When an unacceptable condition or situation is identified, a determination is made as to whether the sa me condition or situation is applicable to other in-scope switchyard or transmission components.
DCPP site QA procedures, review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR 50 Appendix B and are acceptable in addressing corrective actions. The QA program includes elements of corrective action, confirmation process and adm inistrative controls and is applicable to the safety-related and non-safety related syst ems, structures and components (SSCs) that are subject to aging management review.
PG&E Letter DCL-10-158
Page 72 of 73 Appendix B AGING MANAGEMENT PROGRAMS Enhancements Prior to the period of extended operation plant procedures will be enhanced to identify that an engineering evaluation will be conduct ed when a degraded condition is detected that considers the extent of the condition, reportability of the event, potential root causes, probability of recurrence, and the corrective actions required. Confirmation Process - Element 8 DCPP site QA procedures, review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR 50 Appendix B and are acceptable in addressing confirmation proc ess. The QA program includes elements of corrective action, confirmation process and administrative controls and is applicable to the safety-related and non-safety rela ted systems, structures and components (SSCs) that are subject to aging management review. Administrative Controls - Element 9 DCPP site QA procedures, review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR 50 Appendix B and are acceptable in addressing administrativ e controls. The QA program includes elements of corrective action, confirmation pr ocess and administrative controls and is applicable to the safety-related and nonsaf ety-related systems, structures and components (SSCs) that are subj ect to aging management review. Operating Experience - Element 10 Industry operating experience illustrates the pot ential for loss of insulator quality due to salt deposits on switchyard insulators.
Demonstration that this aging management program will be effective is achieved through objective evidence that shows the aging effect of degradation of insulation quality c aused by the presence of salt deposits is being adequately managed. The following exampl es of operating experience provide objective evidence that the Transmission Conductor, Connections, Insulators and
Switchyard Bus and Connections aging m anagement program will be effective in assuring that the intended function of high voltage insulators will be maintained consistent with the current licensing bas is for the period of extended operation.
In March 1993, (IN 93-95) Crystal River Un it 3 experienced a loss of the 230 kV switchyard (normal offsite power to safe ty-related buses) when a light rain caused arcing across salt-laden 230 kV insulators and opened switchyard breakers. In March
1993, Brunswick (LR SER) Unit 2 switchyard experienced a flashover of some high-voltage insulators attributed to a winte r storm. Since 1982, Pilgrim (LR SER) experienced several losses of offsite pow er when ocean storms deposited salt on the 345 kV switchyard, causing the insulator to arc to ground.
Infrared thermography inspections are perfo rmed regularly on switchyard components to detect connections indicating increased resistance. These inspections have
occasionally detected thermal anomalies at connec tions resulting in activities to correct PG&E Letter DCL-10-158
Page 73 of 73 Appendix B AGING MANAGEMENT PROGRAMS the condition prior to failure of the connection or loss of function. Continuation of annual infrared thermography inspections of c onnections during the period of extended operation through the Transmission Conductor, Connections, Insulators and Switchyard
Bus and Connections aging management program will assure the intended functions will be maintained consistent with the current licensing basis for the period of extended operation.
Diablo Canyon is a coastal plant subjec t to frequent and persistent wind, which produces salt spray that can result in insu lator contamination. Instances of corrosion resulting from the exposure of base metal on galvanized components have been observed. During the replacement of 500 kV insulators, it was noted that an insulator had degraded. Although corrosion was the pr ominent and evident degradation, some mechanical wear in the zinc galvaniz ed coating would likely have preceded the degradation in order to expose the base meta
- l. In May of 2007, DCPP experienced a loss of off site power, which was attributed to an insulator failure in the DCPP-Morro Bay 230 kV transmission line, which is not in the scope of license renewal. While
implementing corrective actions, to repl ace similar insulators, transmission line maintenance personnel noted excessive wear on insulator and conductor support
hardware. The degraded hardware was replaced with the installation of new insulators.
The transmission lines from the plant to t he switchyard traverse mountainous terrain, which exposes them to persistent, and frequent high wind conditions. The plant
schedules and, if necessary, conducts hot washes of the 500 kV high voltage insulators
on a six-week frequency and ground or overhead infrared thermography inspections of the 230 and 500 kV insulators at least annually. Operating history has shown this
process is effective in managing contamination.
Industry experience indicates failures of swit chyard bus or transmission conductors are rare. The Transmission Conductor, Connecti ons, Insulators and Switchyard Bus and Connections aging management program will assure that the results of the inspections receive an evaluation for aging to ensure the intended functions will be maintained
consistent with the current licensing bas is for the period of extended operation.
Conclusion The continued implementation of the Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging m anagement program provides reasonable assurance that aging effects will be adequat ely managed such that the systems and components within the scope of license renewal will continue to perform their intended functions consistent with the current lic ensing basis during the period of extended operation.