IR 05000259/2006009

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March 5, 2007

Tennessee Valley AuthorityATTN:Mr. Karl W. SingerChief Nuclear Officer and Executive Vice President6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801

SUBJECT: BROWNS FERRY NUCLEAR PLANT UNIT 1 RECOVERY - NRC INTEGRATEDINSPECTION REPORT 05000259/2006009

Dear Mr. Singer:

On February 3, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed a quarterlyinspection period associated with recovery activities at your Browns Ferry 1 reactor facility. The enclosed integrated inspection report documents the inspection results, which were discussed on February 28, 2007, with Mr. Masoud Bajestani and other members of your staff.We previously informed you, in a letter dated December 29, 2004, of the transition of fourReactor Oversight Process (ROP) Cornerstones (Occupational Radiation Safety, Public Radiation Safety, Emergency Preparedness, and Physical Protection) to be monitored under the ROP baseline inspection program. Consequently, as of January 2005, inspections for thesecornerstones are integrated with Unit 2 and 3 ROP baseline inspections and Integrated Quarterly Reports. They will no longer be documented in the Unit 1 Recovery Quarterly Integrated Reports such as this one. Inspection Report 05000259,260,296/2006005, issued January 30, 2007, is the most recent Unit 2 and 3 Integrated Quarterly Report. Although that report did not contain any site inspections in these cornerstones, they will continue to be documented in ROP integrated quarterly reports such as that one.This inspection examined activities conducted under your Unit 1 license as they relate to safetyand compliance with the Commission's rules and regulations and with the conditions of your license and also with fulfillment of Unit 1 Regulatory Framework Commitments. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. A significant portion of your engineering activities, Unit 1 Recovery Special Program implementation, and modification activities were reviewed during this inspection period and found to be effective with no significant problems identified. However, based on the results of this inspection, Severity Level IV violations of NRC requirements were identified resulting from two examples of inadequate maintenance instructions performed on control rod drive hydraulic control units, failure to identify and correct a condition adverse to quality associated with environmentally qualified motor operated valve actuator T-drains plugged with paint, failure to follow maintenance instructions for environmentally qualified flow transmitters, an inadequate restart test procedure resulting in an unplanned lockout of required Unit 2 ECCS pumps, failure to translate the design basis for station blackout into procedures and instructions, and TVA2inadequate separation of electrical cables. However, the NRC is treating these findings as non-cited violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. If you contest the NCVs in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.:

Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Browns Ferry Nuclear Plant.Overall, we primarily found only minor discrepancies, indicating that your oversight of recoveryactivities was generally effective. However, we will continue to monitor implementation of your corrective actions to address previously identified deficiencies with your fire protection improvements special program and installation of electrical cables.Based on current and previous inspections of Unit 1 Recovery activities associated with eight ofyour Special Programs, the staff has concluded that your implementation of these Special Programs has been adequate and when fully implemented should satisfy NRC regulatory requirements and commitments in your regulatory framework letter dated December 13, 2002.

These Special Programs include the areas of Containment Coatings, Instrument Sensing Lines, Restart Test Program, Environmental Qualification of Electrical Equipment, Component and Piece Parts Qualification, Cable Ampacity, Long Term Torus Integrity, and Large Bore Supports. We do not anticipate additional inspections for these areas.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/Malcolm T. Widmann, ChiefReactor Projects Branch 6 Division of Reactor ProjectsDocket No. 50-259License No. DPR-33

Enclosure:

Inspection Report 05000259/2006009

w/Attachment:

Supplemental Informationcc w/encl: (See page 4)

TVA2inadequate separation of electrical cables. However, the NRC is treating these findings as non-cited violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. If you contest the NCVs in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.:

Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Browns Ferry Nuclear Plant.Overall, we primarily found only minor discrepancies, indicating that your oversight of recoveryactivities was generally effective. However, we will continue to monitor implementation of your corrective actions to address previously identified deficiencies with your fire protection improvements special program and installation of electrical cables.Based on current and previous inspections of Unit 1 Recovery activities associated with eight ofyour Special Programs, the staff has concluded that your implementation of these Special Programs has been adequate and when fully implemented should satisfy NRC regulatory requirements and commitments in your regulatory framework letter dated December 13, 2002.

These Special Programs include the areas of Containment Coatings, Instrument Sensing Lines, Restart Test Program, Environmental Qualification of Electrical Equipment, Component and Piece Parts Qualification, Cable Ampacity, Long Term Torus Integrity, and Large Bore Supports. We do not anticipate additional inspections for these areas.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/Malcolm T. Widmann, ChiefReactor Projects Branch 6 Division of Reactor ProjectsDocket No. 50-259License No. DPR-33

Enclosure:

Inspection Report 05000259/2006009

w/Attachment:

Supplemental Informationcc w/encl: (See page 4)

TVA2G PUBLICLY AVAILABLE G NON-PUBLICLY AVAILABLEG SENSITIVE G NON-SENSITIVEADAMS: G YesACCESSION NUMBER:_________________________OFFICERII:DRPRII:DRPRII:DRPRII:DRPRII:DRSRII:DRSRII:DRSSIGNATUREWCBEXC1CRS1TMRRCC2 by emailGTH1 for/emailNLS2NAMEWBeardenEChristnotCStancilTRossRChouJLenahanNStaplesDATE02/22/0702/27/0702/28/0702/28/0703/01/0703/01/0703/01/07 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO OFFICERII:DRSRII:DRSRII:DRPRIII:DRPRII:DRPRII:DRPRII:DRPSIGNATUREJHB1 by emailTLH4 by phoneLSMRMM by emailTXM1 by emailDSS by emailGAH2 by emailNAMEJBartleyTHoegLMellenMMorrisTMorrisseyDSimpkinsAHuttoDATE03/01/0703/01/0703/01/0702/27/0703/01/0703/01/0703/01/07 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO OFFICERII:DRPRII:DRSRII:DRSRIV:DRPRII:DRPRII:DRSRII:DRSSIGNATURESAW4 by emailMMC by emailMAS1 by emailGEW by emailSPS by emailDCP for by emailGTMNAMESWalkerMCainMScottGWernerSSanchezRSchinGMacDonaldDATE03/01/0703/01/0703/01/0703/01/0703/01/0703/01/0703/01/07 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO OFFICERII:DRSRII:DRSRIII:DRPRII:DRPRII:DRPRII:DRSRIII:DRSSIGNATURENXM by emailCRO for by emailCRM by emailSWF by emailMAB7FJE by emailDXN3 bt naukNAMENMerriweatherCSmithCMooreWFowlerMBatesFEhrhardtDMelendezDATE03/01/0703/01/0703/01/0703/01/0703/01/0703/01/0703/01/07 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO OFFICERII:DRSRII:DRSRII:DRSRII:DRSRII:DRPRII:DRSRII:DRSSIGNATUREBWM1 by emailMSC2 by emailRXL1 by emailECM2 by emailFRWNAMEBMillerMCourseyRLewisEMichelGWisemanDATE03/01/0703/01/0703/01/0703/01/0703/01/07 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO OFFICIAL RECORD COPY DOCUMENT NAME: C:\FileNet\ML070640353.wpd TVA3cc w/encl:Ashok S. Bhatnagar Senior Vice President Nuclear Operations Tennessee Valley Authority Electronic Mail DistributionLarry S. Bryant, Vice PresidentNuclear Engineering &

Technical Services Tennessee Valley Authority Electronic Mail DistributionBrian O'GradySite Vice President Browns Ferry Nuclear Plant Tennessee Valley Authority Electronic Mail DistributionPreston D. SwaffordSenior Vice President Nuclear Support Tennessee Valley Authority Electronic Mail DistributionGeneral CounselTennessee Valley Authority Electronic Mail DistributionJohn C. Fornicola, General ManagerNuclear Assurance Tennessee Valley Authority Electronic Mail DistributionRobert G, JonesActing Plant Manager Browns Ferry Nuclear Plant Tennessee Valley Authority P. O. Box 2000 Decatur, Alabama 35609Robert H. Bryan, Jr., General ManagerLicensing & Industry Affairs Tennessee Valley Authority Electronic Mail DistributionWilliam D. Crouch, ManagerLicensing and Industry Affairs Browns Ferry Nuclear Plant Tennessee Valley Authority Electronic Mail DistributionBeth A. Wetzel, ManagerCorporate Nuclear Licensing and Industry Affairs Tennessee Valley Authority 4X Blue Ridge 1101 Market Street Chattanooga, TN 37402-2801State Health OfficerAlabama Dept. of Public Health RSA Tower - Administration Suite 1552 P. O. Box 303017 Montgomery, AL 36130-3017ChairmanLimestone County Commission 310 West Washington Street Athens, AL 35611Masoud Bajestani, Vice PresidentBrowns Ferry Unit 1 Restart Browns Ferry Nuclear Plant Tennessee Valley Authority P. O. Box 2000 Decatur, AL 35609Robert G. Jones, General ManagerBrowns Ferry Site Operations Browns Ferry Nuclear Plant Tennessee Valley Authority P. O. Box 2000 Decatur, AL 35609 TVA4Report to Karl from Malcolm T. Widmann dated March 5, 2007

SUBJECT: BROWNS FERRY NUCLEAR PLANT UNIT 1 RECOVERY - NRC INTEGRATEDINSPECTION REPORT 05000259/2006009Distribution w/encl:J. Boska, NRR E. Brown, NRR L. Raghavan, NRR C. Evans (Part 72 Only)

L. Slack, RII EICS L. Mellen, RII T. Nazario, RII M. Chernoff, NRR OE Mail (email address if applicable)

RIDSNRRDIRS PUBLIC U.S. NUCLEAR REGULATORY COMMISSIONREGION IIDocket No:50-259 License No:DPR-33 Report No:05000259/2006009 Licensee:Tennessee Valley Authority (TVA)

Facility:Browns Ferry Nuclear Plant, Unit 1 Location:Corner of Shaw and Nuclear Plant RoadsAthens, AL 35611Dates:October 14, 2006 - February 3, 2007Inspectors:W. Bearden, Senior Resident Inspector, Unit 1T. Ross, Senior Resident Inspector, Units 2 and 3 (Sections O1.1, O1.2)

E. Christnot, Resident Inspector C. Stancil, Resident Inspector G. MacDonald, Senior Reactor Analyst (Section F1.1)

J. Bartley, Senior Resident Inspector, Watts Bar (Section E1.2)

T. Hoeg, Senior Resident Inspector, St. Lucie (Section E1.2)

G. Morris, Senior Resident Inspector, Fermi (Section O8.1)

T. Morrissey, Senior Resident Inspector, Crystal River (Section E1.2)

D. Simpkins, Senior Resident Inspector, Hatch (Sections E1.2, E1.3)

G. Werner, Senior Reactor Inspector, RIV (Section E1.2)

A. Hutto, Resident Inspector, Oconee RI (Section E1.2)

S. Sanchez, Resident Inspector, St. Lucie (Section E1.4)

S. Walker, Resident Inspector, Mcguire (Sections E8.1, E8.5)

M. Cain, Senior Reactor Inspector (Sections E1.3, E1.13)

R. Schin, Senior Reactor Inspector (Section E1.13)

M. Scott, Senior Reactor Inspector (Section E1.12)

G. Wiseman, Senior Reactor Inspector (Section F1.1)

N. Merriweather, Senior Reactor Inspector (Section E1.7)

C. Smith, Senior Reactor Inspector (Section E1.6)

L. Mellen, Senior Project Engineer (Section F1.1)

J. Lenahan, Senior Reactor Inspector (Sections E1.8, E1.9)C. Moore, Senior Reactor Inspector RIII (Section E1.2)

W. Fowler, Reactor Inspector (Section E1.2)

M. Bates, Reactor Inspector (Section E1.2)

E. Michel, Reactor Inspector (Section E1.12)

R. Lewis, Reactor Inspector (Section E1.2)

M. Coursey, Reactor Inspector (Section E1.2)

B. Miller, Reactor Inspector (Section E1.2)

D. Melendez, RIII Reactor Inspector (Section E1.2)

N. Staples, Reactor Inspector (Section E1.5)

R. Chou, Reactor Inspector (Sections E1.11, E8.9)

F. Ehrhardt, Operations Engineer (Section E1.3)Approved by:Malcolm T. Widmann, ChiefReactor Project Branch 6 Division of Reactor Projects EXECUTIVE

SUMMARY

Browns Ferry Nuclear Plant, Unit 1NRC Inspection Report 05000259/2006009This integrated inspection included aspects of licensee engineering and modification activitiesassociated with the Unit 1 recovery project. This report covered a three month period of resident inspector inspection. The resident staff performed a reload readiness review prior to the scheduled core reload of Unit 1. In addition, NRC staff inspectors from the regional office conducted inspections of Unit 1 Recovery Special Programs in the areas of electrical cableinstallation/separation; large bore pipe and supports; long term torus integrity; instrument sensing lines; containment coatings; fire protection improvements; environmental qualification of electrical equipment; component and piece parts qualification; maintenance rule; and open inspection items. The inspection program for the Unit 1 Restart Program is described in NRC Inspection Manual Chapter 2509. Information regarding the Browns Ferry Unit 1 Recovery and NRC Inspections can be found at http://www.nrc.gov/NRR/OVERSIGHT/ASSESS/bf1-recovery.html. Per the Partial Cornerstone Transition letter from the NRC to TVA datedDecember 29, 2004, four Reactor Oversight Process (ROP) Cornerstones (Occupational Radiation Safety, Public Radiation Safety, Emergency Preparedness, and Physical Protection)are monitored under the ROP baseline inspection program as of January 2005. Consequently, inspections for these cornerstones are integrated with Unit 2 and 3 ROP baseline inspections and are no longer documented in the Unit 1 recovery quarterly integrated reports such as this one, but in the Unit 2 and 3 Integrated Quarterly Reports.Inspection Results - Operations*The Inspectors concluded that the licensee appeared to be prepared and ready to refuelUnit 1 and enter Mode 5 in compliance with their procedures and regulatory requirements. No significant safety issues, or significant regulatory concerns, were identified regarding the licensee's ability to transition Unit 1 to Mode 5 and safely conduct refueling operations. Inspector walkdowns, observations, and interviews indicated that the system return to service, area turnover, and core reload preparations were adequate to assure public health and safety. Minor process deficiencies and material discrepancies identified by inspectors were appropriately documented and entered into the licensee's corrective action program. (Section O8.1)*Refueling activities and Mode 5 operations were performed in a manner consistent withlicensee procedures and regulatory requirements, with one notable exception that was adequately addressed by the licensee's corrective action program. (Section O8.2) Inspection Results - Engineering*Activities associated with removal of 13 temporary alterations which affected various risksignificant systems did not cause any significant impacts on the operability of equipment required to support operations of Units 2 and 3. Only six active temporary alterations remain on Unit 1. No violations or deviations were identified. (Section E1.1)*System walkdowns, package reviews and interviews with the system engineer indicatedthe Unit 1 Reactor Building Closed Cooling Water, Residual Hear Removal, Core Spray, 4Nuclear Instrumentation, Reactor Protection System, Post Accident Sample System,and Reactor Vessel Level Instrumentation System were adequately turned over as a functional system with pre-approved documented exceptions to operability. For Control Rod Drive, although there were numerous minor material deficiencies, inspectors concluded that the system was adequately turned over to Operations as a functional system without any exceptions and only a few deferrals. None of the material deficiencies would prevent the system from performing its required safety function.

(Section E1.2)*Area turnover guidance and the quality of turnover packages submitted to walkdownparticipants were adequate. With 20% of planned area turnovers complete, areas are being turned over with work still outstanding. Outstanding work and other deficiencies continue to be identified by restart area coordinators and plant management during walkdowns and subsequently punch listed as in the same process for system turnover.

The NRC intends to continue inspection efforts of selected areas to determine consistent program implementation and resolution of select punchlist items. The inspectors determined that activities associated with the Unit 1 restart area turnover process did not cause any significant impact to the operability of equipment required to support operations of Units 2 and 3. No violations or deviations were identified.

(Section E1.3)*Implementation of restart testing activities was generally acceptable. Minor testdeficiencies which did not affect the results of the testing, were identified during performance of testing. Licensee processes were effective at identifying problems before components were placed in service. (Section E1.4)*A Severity Level IV Non-Cited Violation associated with an inadequate test instructionwas identified during the current inspection. The inadequate instruction resulted in the unplanned lockout of required Unit 2 ECCS pumps. (Section E1.4)*An example of a Severity Level IV Non-Cited Violation was identified for a configurationcontrol issue in the Cable Spread Room. The inspector found that the installed Division I conduit consisting of control cables was routed within a Division II cable tray instead of as depicted in the layout drawing. This resulted in the as-built configuration for cables in the plant deviating from design drawings and Integrated Cable Raceway Data System.

Due to the need to inspect additional examples for external and internal separations, additional inspections will be required to determine if the Electrical Cable Installation and Separation Special Program is being implemented satisfactorily. (Section E1.5)*A second example of a Severity Level IV Non-Cited Violation was identified for aconfiguration control issue in the Auxiliary Instrument Room. The inspector found that the installed Division II cables were incorrectly labeled and routed within the "top hat" region of Division I raceway above an instrument and control panel without the required independence being maintained. (Section E1.5)*An unresolved item was identified for a configuration control issue involving divisionalseparation configurations within the "top hat" area located above instrument and control panels within the Auxiliary Instrument Room. The inspector found that internal panel separation was extended into the "top hat" without defined boundaries to distinguish 5divisional separation. This resulted in cables considered divisional and non-divisionalbeing routed in the same enclosure without adequate separation. (Section E1.5)*Design changes implemented to correct cable ampacity problems involving powerfeeder cables for the RHR and CS pump motors were technically adequate, and provided positive margin for the power feeder cables ampacity. Additionally, the plant modifications which replaced transformer primary feeder cables for transformers TS1A and TS1B feeding 480 V Shutdown Boards 1A and 1B respectively, demonstrated that positive margin had been established for the transformer primary power feeder cables ampacity. The ampacity calculations completed for the cables inspected, demonstrated that the cables were correctly sized in accordance with TVA's Design Standard DS-E12.6.3, and that the installed cables are capable of supporting the restart of Unit 1.

Based on the results of this inspection, no additional inspection of this special program is planned. (Section E1.6)*The inspectors concluded that the Special Program for Environmental Qualification ofElectrical Equipment was adequate to support Unit 1 restart. The licensee's program will result in most of the existing EQ components, cables, and splices being replaced on Unit 1. For those existing components that will not be replaced, the licensee has performed field verifications and record reviews to verify that the equipment was still EQ qualified. The inspectors examined a select sample of EQ components to confirm that the program was being adequately implemented. No further inspection of this Special Program is planned. (Section E1.7) *The inspectors concluded that the Special Program for Component/Piece PartsQualification was adequate to support Unit 1 restart. The licensee's Component/Piece Parts Qualification Special Program required that the maintenance records for the 27 saved components be reviewed in detail to verify that the EQ qualification had not been invalidated or degraded by the use of unqualified piece parts or sub-components during past maintenance activities. The inspectors examined a select sample of EQ components to confirm that the program was being adequately implemented. No further inspection of this Special Program is planned. (Section E1.7) *A Severity Level IV Non-Cited Violation was identified for failure to replace the O-ringsafter both transmitter housing covers were removed. This issue was documented in the licensee's corrective action program. (Section E1.7)*A Severity Level IV Non-Cited Violation was identified for failure to identify that a motorT-drain on a Limitorque operator had been plugged with paint. This issue was documented in the licensee's corrective action program. (Section E1.7)*The Instrument Sensing Line slope correction activities were performed in accordancewith documented requirements. The inspectors determined that the licensee's program for correction of the instrument line slope deficiencies complies with the design criteria, commitments to NRC, and NRC requirements. No further inspections of Instrument Sensing Lines Special Program are anticipated. (Section E1.8)*The inspectors determined that the licensee's program for inspection of protectivecoatings in the drywell, and identification and documentation of deficiencies were 6consistent with their commitments to NRC. Work orders have been prepared tocomplete corrective actions prior to restart. No further inspections of the containment coatings Special Program are anticipated. (Section E1.9)*The licensee's Restart Test Program is providing adequate assurance that safetysystems would fulfill their safe shutdown functional requirements and support the safe return to operation on Unit 1. NRC observation and review of ongoing testing activities will continue throughout the remainder of the system acceptance testing and power ascension testing programs. However, no further program inspections are planned for this Special Program. (Section E1.10)*The inspectors found that licensee performance was adequate in the Long Term TorusIntegrity Special Program based upon the independent walkdowns of selected pipesupports; design changes and work orders; and problem resolution. No violations or deviations were identified during this inspection. Long Term Torus Integrity SpecialProgram activities were adequately performed in accordance with documented requirements based on this and all previous inspections. No further inspections are anticipated for this Special Program. (Section E1.11)*Large Bore Piping and Support Special Program activities were adequately performed inaccordance with documented requirements based on this and all previous inspections.

No further inspections are anticipated for this Special Program. (Section E1.11)*The inspectors verified selected systems, structures and components were scopedadequately in accordance with the Maintenance Rule, and reviewed the licensee's strategy for verifying adequate goals and performance criteria had been established to satisfy the requirements of the Rule. The inspectors verified that the Unit 1 integration into the operating unit's Maintenance Rule program would include Performance Evaluations and that the licensee assessed and managed the risk of maintenance activities in accordance with the Rule. (Section E1.12). *A Severity Level IV Non-Cited Violation was identified involving design controlassociated with calculations and procedures which did not ensure that emergency diesel generators would have an adequate cooling water supply for station blackout. The licensee needs to complete adequate corrective action for this nonconforming condition to establish full compliance with the requirements of 10 CFR 50.63 (the Station Blackout Rule) prior to restart of Unit 1. (Section E1.13)*The licensee had committed to send a letter to the NRC documenting compliance withthe SBO rule for Unit 1 and combined three-unit operation, but had not yet sent such a letter. (Section E1.13)*The licensee's initial corrective actions associated with a previously identified issueassociated with tape potentially contaminated with chlorides and a foreign material exclusion concern were not acceptable. Prompting was required before the tape was removed and analyzed for chlorides. Prompting was required again before external cleanliness verifications were performed. However, based on final test swipe results which showed no chlorides, the inspectors concluded no potential for damage to the stainless sensing lines had existed. (Section E7.1)7Inspection Results - Maintenance*The inspectors identified two examples of a Severity Level IV Non-Cited Violation forfailure to provide adequate instructions for maintenance on Hydraulic Control Units.

Both issues were documented in the licensee's corrective action program. Subsequent review of licensee corrective actions were determined to be adequate. (Section M1.1)Inspection Results - Plant Support*The Fire Protection Special Program will remain open pending the final Safe ShutdownInstructions review. No further inspections are planned for the fire protection systems with the exception of Thermo-Lag, Safe Shutdown Instructions, communications, and the backup control panel. (Section F1.1)

Table of ContentsI. Operations................................................................O8Miscellaneous Operations Issues....................................1O8.1Fuel Load Readiness .......................................1O8.2Refueling Operations .......................................6II. Engineering..............................................................7E1Conduct of Engineering...........................................7 E1.1Temporary Plant Modifications ...............................7 E1.2System Return to Service Activities ............................9 E1.3Area Turnover Activities ...................................19E1.4System Restart Testing Program Activities .....................22E1.5Restart Special Program Activities - Cable Installation and CableSeparation ..............................................43E1.6Restart Special Program Activities - Cable Ampacity..............48E1.7Restart Special Program Activities - Environmental Qualification (EQ) ofElectrical Equipment and Piece Parts Qualification...............50E1.8Restart Special Program Activities - Instrument Sensing Lines......54E1.9Restart Special Program Activities - Containment Coatings.........57E1.10Restart Special Program Activities - Restart Testing program.......58E1.11Restart Special Program Activities - Large Bore Piping and Supports andLong Term Torus Integrity..................................59E1.12Readiness for Maintenance Rule.............................62E1.13Station Blackout..........................................63E7Quality Assurance in Engineering Activities ..........................67E7.1Licensee Quality Assurance Oversight of Recovery Activities(Identification and Resolution of Problems).....................67E8Miscellaneous Engineering Issues .................................69E8.1(Closed) Generic Letter (GL) 92-04 and IE Bulletin (IEB) 93-03,Resolution of Issues Related to Reactor Vessel Water Level Instrumentsin BWRs................................................69E8.2(Closed) GL 89-10, Safety-Related Motor-Operated Valve Testing andSurveillance.............................................70E8.3(Closed) GL 96-01, Testing of Safety-Related Logic Circuits........71E8.4(Closed) GL 97-04, Assurance of Sufficient Net Positive Suction Head forEmergency Core Cooling and Containment Heat Removal Pumps...72E8.5(Closed)Bulletin 96-03, Potential Plugging of Emergency Core CoolingSuction Strainers by Debris in Boiling Water Reactors.............73 E8.6(Closed) Inspector Followup Item (IFI) 259/95-55-01, Review of LicenseeFinal Safety Analysis Report (FSAR) commitments for Continuous AirMonitors (CAMs) Associated with Units 1 and 3..................73E8.7(Closed) IEB 79-02, Pipe Support Base Plate Designs Using ConcreteExpansion Anchors, and IEB 79-14, Seismic Analysis for As-Built Safety-Related Piping Systems....................................73E8.8(Closed) 10CFR 21 Report 2006-21-01, Potential Defect in OTEK PanelMeters.................................................73E8.9(Closed) Unresolved Item (URI) 259/06-06-01, Adequacy of SRTSActivities................................................74E8.10(Closed) URI 259/06-08-02, Impact of Duct Tape on Instrument Tubing 75E8.11(Discussed) Unresolved Safety Issue (USI) A-44, Station Blackout (SBO)..................................................75III. Maintenance...........................................................75M1Conduct of Maintenance.........................................75M1.1Inadequate Control Rod Drive (CRD) Scram Valve MaintenanceInstruction...............................................75IV. Plant Support...........................................................77F1Fire Protection.................................................77F1.1Restart Special Program Activities - Fire Protection Improvements...77V. Management Meetings....................................................82X1Exit Meeting Summary...........................................82

REPORT DETAILS

Summary of Plant StatusUnit 1 has been shut down since March 19, 1985, and had remained in a long-term lay-upcondition with the reactor defueled until December 2006. The licensee initiated Unit 1 recovery activities to return the unit to operational condition following the TVA Board of Directors decision on May 16, 2002. During the current inspection period, reinstallation of plant equipment and structures continued. Recovery activities included completion of replacement of components in the drywell and reactor building; reinstallation of balance-of-plant piping and turbine auxiliary components. The amount of restart testing, system return to service, and area turnover activities significantly increased during this reporting period as the Unit 1 recovery effort completed their transition away from bulk construction work. Additionally, the licensee returned a significant number of safety related systems to service and reloaded fuel in the Unit 1 reactor vessel.I. OperationsO8Miscellaneous Operations IssuesO8.1Fuel Load readiness (60705, 71111.20, 71152, 72500B)

a. Inspection Scope

The objective of this inspection was to ascertain the licensee's readiness to enter Mode5, and conduct a reactor refueling campaign of Unit 1, after approximately 15 years of lay-up and five years of recovery (e.g., design evaluation, reconstruction, and testing).

In general, the inspectors evaluated the licensee's preparedness for Unit 1 reload using inspection procedures IP 60705, Preparation for Refueling; 72500B, Initial Fuel Loading Procedure; IP 71111.20, Refueling and Other Outage Activities; and IP 71152, Identification and Resolution of Problems, as guidance. During the conduct of this Unit 1 Reload Readiness Review (RRR), a team of inspectors attended management review meetings, interviewed responsible personnel, reviewed and evaluated applicable procedures, examined supporting documents, and conducted independent walkdowns of risk significant systems. All licensee activities in preparation for Unit 1 reload and Mode 5 operation were inspected against approved plant procedures, established programs and policies, and regulatory commitments and requirements.More specifically, the inspection scope of the RRR team encompassed the followingactivities that were accomplished primarily during the week of December 10, 2006, prior to Unit 1 fuel load: *Verified that the SPOC II was complete for all reload required systems, and thatthese systems were turned over to Operations, and declared operable when required. *Reviewed outstanding Integration Task Equipment List (ITEL) punch list items ofselected safety and/or risk significant systems required for core reload. Also 2reviewed outstanding work orders (WO) and problem evaluation reports (PER)coded for reload.*Conducted detailed system alignment walkdowns of the Core Spray (CS)System, Fuel Pool Cooling and Cleanup (FPCC) System, Reactor Building Closed Cooling Water (RBCCW) System; Residual Heat Removal Service Water (RHRSW) System, Emergency Equipment Cooling Water (EECW) System, and the Standby Liquid Control (SLC) System. *Conducted area walkdowns that included all four quads; the Torus; reactor watercleanup (RWCU) pump room, heat exchanger room, and demineralizer rooms; spent fuel pool cooling pump and heat exchanger area; and RHRSW/EECW pump rooms. *Verified that design changes, primary and critical drawings, and systemoperating instructions were closed out, updated and/or issued, as applicable; or evaluated and dispositioned as not required for fuel load, for the following risk significant systems: RHRSW, SLC, RBCCW, Residual Heat Removal (RHR),

CS, Control Rod Drive (CRD), Reactor Protection System (RPS), 250 Volt DC Distribution, and parts of Reactor Vessel Level Instrumentation and Post Accident Sampling. *Reviewed general operating instruction 0-GOI-100-3C, Fuel MovementOperations During Refueling, and the Unit 1 Core Operating Limits Report (COLR), including supporting documents.*Verified plant conditions and parameters required by Technical Specifications(TS) and operating procedures were set for Mode 5 operations, including detailed main control room walkdowns of the Unit 1 main control boards. *Confirmed organizational readiness of the principal departments (e.g.,Operations, Engineering, Maintenance, RadCon, etc.) to support safe fuel load operations by verifying Operational Readiness Review (ORR) action items required for Unit 1 reload were adequately resolved and/or dispositioned. *Verified Operations onshift staffing was adequate to support safe fuel loadoperations, and applicable training on Unit 1 specific differences were conducted. *Verified reload related issues were entered into the corrective action program. Also reviewed resolution of selected issues and verified selected corrective actions were adequately implemented. *Attended important meetings responsible for review, recommendation, and/oroversight of reload readiness, such as - Plant Oversight Review Committee (PORC) reload meetings on December 11, 13, and 15; Management Review Committee (MRC) meetings on December 12 and 13; Work Order Review Group meeting on December 12; and Nuclear Safety Review Board (NSRB) meeting on November 21.

3*Assessed system health of all reload required systems.*Examined the shutdown risk assessment tool (i.e., Outage Risk Assessment andManagement (ORAM)) developed specifically for Unit 1, including associated procedures (e.g., O&SSDM-4.0, Operational Defense-In-Depth). Also reviewed Unit 1 Reload Risk Assessment Report.*Reviewed outstanding Unit 1 temporary modifications, operator workarounds(OWA), and disabled annunciators. *Verified overall completion and/or resolution of all applicable prerequisites in 1-TI-270, Appendix A, Fuel Loading Prerequisite Checklist.

b. Observations and Findings

The inspectors did not identify any significant safety issues, or significant regulatoryconcerns, regarding the licensee's ability to transition Unit 1 to Mode 5 and safely conduct refueling operations. However, the inspector's did identify a number of minor findings/observations that were entered into the licensee's corrective action program.

The more significant of these minor issues are described below.During the review of 1-TI-270, Appendix A, Fuel Loading Prerequisite Checklist, theinspectors noticed that there was no signature for the Security department in Section 15.0, Organizational Readiness. The licensee agreed that this was an oversight and promptly corrected the omission. The inspectors also noticed that there was no consolidated signature in the checklist for required fuel load procedures (with exception of surveillance procedures). However, inspectors were able to verify that there were no outstanding required fuel load procedures through several different processes: System Return to Service (SRTS) process, Design Change Notice (DCN) process, and the three organizations responsible for systemically tracking procedures (Operations, Maintenance, and Engineering). The inspectors noted that the licensee's processes were not easily auditable for verifing all required surveillances for a plant operating mode or milestone, in this case fuel load or Mode 5.The Unit 1 main control room annunciator system was modified and modernized duringthe recovery project, and as a result was significantly different than the annunciator systems for Units 2 and 3. The inspectors examined the Unit 1 specific just-in-time (JIT)training for DCN 51107, Unit 1 Annunciator System; reviewed the associated training attendance records; and interviewed licensed Unit 1 operators. Based on this inspection, the inspectors' determined that approximately one third of the Operations licensed onshift personnel did not receive the subject JIT training. However, once Operations management was notified, the remainder of the Operations organization was promptly trained.During an inspection of the Unit 1 disabled annunciator logs, the inspectors determinedthat the disabled logs for annunciator panel U1-XA-55-8A had not been reviewed by the licensee for impact on Unit 1 reload and Mode 5 operations. Furthermore, the inspector concluded that the reason for the disabled alarm input to panel #34 "Diesel Auxiliary 4Board Bkr Tripout," was no longer valid. The licensee initiated PER 116726 to resolvethese deficiencies.For configuration control and work management of Unit 1 systems turned over toOperations, the inspectors examined the use of SPP-7.2, Outage Management, and determined that the licensee had not specifically evaluated the applicability of SPP-7.2 for the transition of Unit 1 from a recovery project to outage management. In particular, the licensee had not addressed the provisions of Section 3.2.7, Outage Safety Plan. In response to the inspectors' concerns the licensee developed an Outage Safety Plan for Unit 1 and committed to review SPP-7.2 for any other relevant sections. Inspectors reviewed 0-GOI-100-3C, Fuel Movement Operations During Refueling, andverified precautions, limitations, prerequisites, and initial conditions met licensee commitments and regulatory requirements, with one exception. The licensee did not plan to maintain a reciprocal multiplication (1/M) plot because they were crediting a procedural check for monitoring the doubling of subcritical multiplication counts.

However, the subcritical multiplication doubling check comparison was only after each single fuel assembly loaded in the core, and was neither integrated nor trended to foretell an unexplained rise in counts and potential unanticipated criticality. Based on the inspectors' concern, the licensee reactivated an existing procedure, 0-TI-147, Fuel Loading, that would use a 1/M plot to verify adequate shutdown margin during refueling activities. The inspectors subsequently reviewed 0-TI-147 and determined it addressed the inspectors' concerns.Inspectors reviewed the technical evaluation for the Browns Ferry Unit 1 Cycle 7 COLRand supporting documents, including the 50.59 screening, General Electric NSAC 164L guidelines, source range monitor (SRM) TS and bases, and core loading methodology.

Inspectors identified an inconsistency between the technical evaluation and the core loading sequence. The technical evaluation stated that the Cycle 7 core loading wouldbe performed using a "spiral" loading sequence. The developed core loading sequence was a modified spiral consisting of blocking (surrounding the SRM with fuel) and bridging (loading across the core quadrant to block the next SRM) until a continuous fueled region is established and continuing on with spiral sequencing. The modified spiral is more conservative as discussed in NSAC 164L, Guidelines for BWR Reactivity Control During Refueling. The discrepancy was entered in the licensee's corrective action program as PER 116620 and corrected with a revision to the technical evaluation.Inspectors performed plant system walkdowns of selected systems (see scope above). The following issues were identified, with associated PERs:*CS drain valve 1-DRV-75-710, PSC WTR HD TK PMP 1A DRIP PAN DR, wasopen with tygon hose attached vice closed as required by the lineup checklist.

No other configuration control was apparent. The licensee indicated Work Order 06-726716 was written for a clogged valve. (PER 116659)*The locked valve seal for locked closed valve 1-SHV-75-512B, CS PMP 1BSUCT DR LINE SHV, was broken. (PER 116599)5*Instrument tube vent valves upstream of the following instrument isolations hadno labels or identifying tags (PER 116976):1-RTV-75-76A1-PI-75-041-PI-75-411-RTV-75-76B1-PI-75-071-PI-75-35 1-RTV-75-75A1-PI-75-161-PI-75-44 1-RTV-75-75B1-PI-75-32*Numerous valves identified as closed and capped on drawing 1-47E814-1, FlowDiagram Core Spray System, were not indicated as capped on the valve lineup checklist, 1-OI-75, Attachment 1. All were actually capped in the field except 1-DRV-75-25. (PER 116744) *Vent valve on fuel pool cooling header drain to the main condenser was not ondrawing 1-47E855-1, Flow Diagram Fuel Pool Cooling System, nor was it in 1-OI-78, Attachment 1A Valve Lineup Checklist. Valve was located between valves 1-CKV-78-567, 1-DRV-78-569, and 1-FSV-78-7. (PER 116727)*Drain valve 1-DRV-78-551, SEAL RUPTURE DRN TO CNDR, was locked closedin the field, but 1-OI-78, Attachment 1A required only closed. The licensee initiated Procedure Change Request (PCR) 06-003493.*RBCCW valve 1-70-568, Reactor Building Equipment Drain Sump HeatExchanger Sample and Test valve, was found closed. The RBCCW valve lineup sheet and the drawing showed this valve was required to be open. (PER 116750)*EECW valve 1-SHV-067-0613, RHR Seal HX 1D Sply SOV, was required to belocked open. The valve was open but was not locked. There was no chain on the valve body to use with the locking device. (PER 116587) The inspectors met with licensee management to discuss their comprehensive actionplan to address the causes and extent of condition associated with the numerous valve discrepancies described above. As part of their corrective action plan, the licensee conducted single-party valve checklist verifications for RHR and CRD system valves, and numerous other selected valves in various systems that were deemed vulnerable to the same discrepancies. Furthermore, the licensee conducted a 100% verification of all valves in their locked valve program. No other discrepancies were identified. The inspectors' considered the licensee's corrective actions to be comprehensive and timely.

c. Conclusions

The inspectors did not identify any significant safety issues, or significant regulatoryconcerns, regarding the licensee's ability to transition Unit 1 to Mode 5 and safely conduct refueling operations. The Inspectors concluded that the licensee appeared to be prepared and ready to begin refueling Unit 1 and enter Mode 5 in compliance with plant procedures, processes, and TS. The results of inspector walkdowns, observations, and interviews indicated that the system return to service, area turnover, and core reload preparations were adequate to assure public health and safety. Minor 6process deficiencies and material discrepancies identified by inspectors wereappropriately documented and entered into the licensee's corrective action program.O8.2Unit 1 Core Reload and Transition to Mode 5 (71111.20)

a. Inspection Scope

On December 15 - 23, 2006, the inspectors examined critical activities associated withcore reload of Unit 1 and transition to Mode 5 operations. Some of the more significant inspection activities were as follows:*Witnessed Unit 1 refueling operations, from the Unit 1 MCR and Refueling Floor,conducted in accordance with 0-GOI-100-3C, Fuel Movement Operations DuringRefueling; 0-TI-147, Fuel Loading; and, Fuel Assembly Transfer Forms (FATFs).*Verified selected Section 3.0, Precautions and Limitations, and Section 4.0,Prerequisites, of 0-GOI-100-3C.*Walked down Unit 1 control boards, toured reactor building areas with in-serviceequipment, and interviewed operators to verify compliance with Mode 5 TS requirements in general, and TS Section 3.9, Refueling Operations, in particular. *Reviewed and verified Unit 1 outage risk assessment (i.e., ORAM).*Evaluated emergent work activities for impact on refueling operations.

• Attended MRC and work control management meetings.

• Reviewed PERs generated during Unit 1 refueling activities and Mode 5operations to verify that initiation thresholds, priorities, and significance levels were properly assigned. Selected aspects of the resolution and implementation of corrective actions for several PERs were also examined and/or verified.*Investigated the circumstances, cause and immediate corrective actionsregarding a fuel move error that occurred on December 17, 2006 (PER 116882).

b. Findings

No findings of significance were identified.

7II. EngineeringE1Conduct of EngineeringE1.1Temporary Plant Modifications (71111.23)

a. Inspection Scope

The inspectors reviewed licensee procedure SPP-9.5, Temporary Alterations. Theinspectors also reviewed and observed ongoing activities associated with System 35, Main Turbine Generator Stator H2 Seal Oil and Cooling (MTGH2); System 56, Temperature Monitoring System (TMS); System 64D, Primary Containment Isolation System (PCIS); System 74, Residual Heat Removal (RHR); System 75, Core Spray System (CSS); System 77, Radiological Waste Treatment (RWT); System 85, Control Rod Drive (CRD); System 90, Radiation Monitoring System (RMS); System 92, Neutron Monitoring System (NMS); and System 99, Reactor Protection (RPS). The inspectors verified that 10 CFR 50.59 screening and technical evaluations against the system design bases documentation, including the Final Safety Analysis Report (FSAR) and TS and reviewed selected completed work activities of the system to verify that installation and/or removal were consistent with the modification documents and the Temporary Alteration Control Form (TACF). In addition, special emphasis was placed on the potential impact of these temporary modifications on operability of equipment required to support operations of Units 2 and 3.

b. Observations and Findings

Historical Temporary AlterationsThe inspectors reviewed and observed selected closure activities associated with 12historical temporary alterations that had been installed in the 1984 to 1988 time frame prior to the start of the Unit 1 recovery program.

These TACFs were no longer needed due to implementation of permanent modifications.*1-84-058-92, installed in February 1984, was initiated to move the IRM ChannelA signal cable from terminal 31B to terminal 27B on Drywell penetration BA . *1-84-066-92, installed in November 1984, was initiated to replace the IRMconnectors at penetrations A and B. *1-84-074-74, installed in June 1984, was initiated to was initiated to install anonsite fabricated coupling on the 1A PSC pump, the Keep Filled system for the ECCS. *1-84-100-99, installed in November, 1984, was initiated to install internalconduits in the RPS cabinet and reroute existing cables through the conduit in order to prevent a single failure.

8*1-85-12-92, installed in March 1985 was initiated to replace the IRM Channels Aand C signal cable penetration connectors with modified connectors located at the Drywell to Reactor Building penetrations.*1-85-100-56, installed in August 1985, was initiated to install a temporary cableto connect a spare thermocouple on the reactor vessel to the Temperature Monitoring System.*1-85-021-77, installed in July 1985, was initiated to replace the Robert ShawModel 351 level switch with a Robert Shaw Model 352 level switch for level switch 1-LS-77-25C.*1-85-023-64D, installed in August 1985, was initiated to attach temporaryidentification tags on instrumentation root valves.*1-85-024-85, installed in July 1985, was initiated to install and connect temporarytubing to valve 1-SHV-85-507A located on elevation 541 of the Reactor Building in order to sample the CRD fluid.*1-85-027-35, installed in August 1985, was initiated to install two sample lines onthe main generator stator cooling water system.*1-86-024-74, installed in November 1986, was initiated to remove a Torus blindflange, turn the flange over to Unit 2, and replace the flange with a temporary onsite fabricated blind flange. *1-89-001-90, installed in September 1989, was initiated to remove jumpers todisable the Group 1 PCIS and Main Steam Isolation Valves signals out of service.The inspectors reviewed the removal activities associated with the above temporaryalterations and verified that removal was supported by the implementation of a permanent modification. Specific Design Changes (DCNs) reviewed are listed in the attachment. Unit 1 Recovery Temporary AlterationsThe inspectors reviewed and observed selected removal activities associated with onetemporary alteration that had been installed in the 2002 to 2005 time frame to support ongoing Unit 1 recovery activities. This TACF, 1-04-010-99, affected the RPS and PCIS systems, and involved the power supplies for the RPS Channels A and B, the PCIS Trip Channels A and B, and the Backup SCRAM system circuitry. This TACF was closed due to implementation of permanent modifications. The inspectors verified that the temporary alteration was no longer needed due to completion of DCN 51085, ECCS Analog Trip Unit Power Supplies, Electrical - Control Bay, System 256.

9Remaining Unit 1 Active Temporary AlterationsAt the end of this report period a total of six TACF's remained active on Unit 1. Thesystems affected included System 01, Main Steam; System 03, Reactor Feed Water; System 44, Building Heating; System 66, Offgas, Recombiner, and Charcoal Filter; System 70, Reactor Building Closed Cooling Water; and System 79, Fuel Handling.

The open TACF's were the following:*1-84-073-01, installed in April 1984, to install test sensing lines to pressuretransmitters used for turbine performance testing.*1-84-053-03, installed in September 1984, to allow for the removal of selectedwiring to permit the operation of the 1C reactor feed water pump turbine.*1-84-056-03, installed in March 1985, to cap the individual air cylinders on thereactor feed pump discharge testable check valves 1-CKV-03-92, 93, and 94.*1-85-022-066, installed in August 1985, to install a sample valve to obtain asample of the chill water for the Off Gas System.*1-05-004-044, installed in June 2005, to install Tee fittings, ball valves, andflexible piping to rout chilled water through the existing building heating coils to cool the building.*1-06-008-079, installed in December 2006, to install Unistrut channelassemblies on the Unit 1 refueling bridge crane to facilitate the installation of the air hose reel from the Unit 3 refueling bridge crane, due to the Unit 3 hose reel being opposite handed to the Unit 1 hose reel.These TACF's will remain open pending completion of applicable system DCN's andremoval by issued work orders. The inspectors determined that the licensee's current plans included removal of all active temporary alterations on Unit 1 prior to restart. The inspectors will continue to monitor licensee activities in this area.

c. Conclusions

The inspectors determined that activities associated with removal of 13 temporaryalterations which affected various risk significant systems did not cause any significant impacts on the operability of equipment required to support operations of Units 2 and 3.

Only six active temporary alterations remain on Unit 1. No violations or deviations were identified.E1.2System Return to Service Activities (37550, 37551)

a. Inspection Scope

The inspectors continued to review and observe portions of the licensee's ongoingSystem Return to Service (SRTS) activities. The SRTS activities were performed in accordance with Technical Instruction 1-TI-437, System Return to Service Turnover 10Process for Unit 1 Restart. The level of SRTS activities continued to increase duringthis reporting. System Pre-Operability Checklist (SPOC) II packages were approved by the Browns Ferry Unit 1 restart organization during the current inspection period for the following risk significant systems: System 70, Reactor Building Closed Cooling Water (RBCCW); System 74, Residual Heat Removal (RHR); System 75, Core Spray (CS);

System 85, Control Rod Drive; System 92, Neutron Monitoring; System 99 Reactor Protection System (RPS); and partial Systems 43-01, Post-Accident Sampling (PASS)and 003-01, Reactor Vessel Level Instrumentation (RVLIS). For these systems, inspectors reviewed completed SPOC II packages, performed in-depth system walkdowns including the drywell if applicable, observed SPOC II review boards when the schedule permitted, reviewed completed support paperwork, and conducted interviews with licensee personnel. The inspectors continued to evaluate the effectiveness of improvements to thelicensee's SRTS process which were initiated to address weaknesses previously identified by the inspectors and by the licensee during a self assessment. NRC inspection findings related to those weaknesses were previously discussed in Inspection Report 50-259/2006-06. These improvements included increased management expectations regarding ownership by personnel from the operating organization, greater level of involvement by management (both from Unit 1 and the operating units), and creation of separate plant review and acceptance boards tasked with providing independent oversight of SPOC I and SPOC II turnover activities for each system which undergoes SRTS activities.Additionally, inspectors other than the resident staff performed independent systemreadiness reviews on selected risk significant systems which had completed the SPOC II system turnover process. The inspectors reviewed the completed SPOC II package for their assigned System, performed a detailed independent system walkdown, and reviewed completed documentation to support the SPOC II package.

b. Observations and Findings

The SRTS process consisted of three parts: System Plant Acceptance Evaluation(SPAE), which consists of verification of design changes, engineering programs analysis, drawings, calculations, corrective action items, and licensing issues; SPOC I,which consists of the completion of items required for system testing; and SPOC II, which consists of the completion of system testing and the completion of items that affect operational readiness. All required system SPAE packages had previously been issued by the licensee prior to the start of this reporting period.Specific SRTS activities observed by the inspectors included periodic meetings todiscuss the SRTS status, which included the status of the SPOC I checklists, status of the SPOC II process, and status of outstanding work items and identified deficiencies.

Documents and activities reviewed included System SPOC exceptions, deferrals, and special operating conditions; system testing requirements; temporary alterations; completed WOs; engineering calculations; SRTS open items punchlist (OIP); and various PERs associated with the SRTS process. The inspectors also held discussionswith engineering and operations personnel responsible for SRTS activities and performed walkdowns of selected portions of affected systems.

11The inspectors noted that licensee management expectations were strengthened andbetter communicated resulting in increased operating unit ownership; increased operating unit organization participation in SPOC meetings, testing, and walkdowns; and systems being turned over in a much more ready condition resulting in fewer open items. The inspectors review of corrective actions associated with previously identified weaknesses in the licensee's SRTS process is discussed further in Section E8.9.

b.1SPOC I and II Boards and Walkdown ActivitiesIn addition to periodically observing daily SPOC status meetings, the inspectorsobserved SPOC plant system walkdowns and management review and acceptance boards. SPOC II walkdowns were independently performed on Systems 70 Reactor Building Closed Cooling Water, 74 Residual Heat Removal, 85 Control Rod Drive, 92 Neutron Monitoring, and 99 Reactor Protection. Inspectors observed SPOC I management review boards on Systems 24 Raw Cooling Water and 92 Neutron Monitor, and partial Systems Reactor Vessel Level Instrumentation (RVLIS) and Post Accident Sampling (PASS). Inspectors observed SPOC II management review boards on Systems 24 Raw Cooling Water, 85 Control Rod Drive, 90 Radiation Monitoring, and 92 Neutron Monitoring, and partial Systems RVLIS and PASS.Independently performed SPOC system walkdowns by inspectors validated that licenseewalkdowns were adequately conducted in accordance with 1-TI-437 System Return to Service (SRTS) Turnover Process for Unit 1 Restart, Appendix D SPOC Walkdown Instruction and Attachment 6 SPOC Walkdown. Operational deficiencies and material discrepancies identified by inspectors and licensee representatives were appropriately documented and dispositioned. The inspectors determined that SPOC walkdown and review board activities associated with the SRTS turnover process were being adequately implemented. b.2System 70, Reactor Building Closed Cooling Water (RBCCW) System ReadinessInspectionInspectors reviewed the System Return to Service Open Item Punchlist (SRTS-OIP) andnoted three deferral items. Deferral item PL-06-3618, which must be completed prior to Reactor Pressure Vessel hydrostatic testing, documents the inability to obtain Reactor Recirculation Pump seal cooler flow within the acceptable range. Design Engineering is reviewing the flow data to determine whether it is acceptable as-is or if there is a need to initiate corrective actions. Two other deferral items associated with minor control air leak repairs and drywell cooler flow balancing must be completed prior to drywell closeout.Inspectors performed an in-depth system walkdown. One deficiency was noted by theinspectors during the ongoing walkdown. The electrical flex conduit to MVOP-70-0048 was found pulled away from the valve. The licensee initiated WO 06-725937-000 to address this deficiency.Inspectors performed an in depth review of the testing package completed for thesystem pre-operability review. No deficiencies were noted.

b.3System 74, Residual Heat Removal (RHR) System Readiness InspectionThe RHR SPOC II package has five exceptions, which must be cleared prior todeclaration of operability.The inspectors reviewed the SRTS-OIP. The milestone designation for WO's 02-012392-001, 02-012392-002, 02-012392-005, 02-012392-006, 02-012392-007, and 02-012392-008 were coded ME (EDG load Acceptance Test) when the correct designation was M2 (Mode 2). PER 115715 was issued to address this error and the entries were corrected.The inspectors performed an in-depth walkdown of the RHR system. During thewalkdowns the following deficiencies were identified:*RHR valve 1-SHV-074-010 was observed as having a packing leak. (WO 06-725337-000)*Inside the drywell, spring can 147B400-114 located at Elevation 604 Azimuth108, was observed to have a tape measure and various plastic bags located inside the can. (PER 115052) *Two anchor bolts for support RHR-1-R-035D lacked full thread engagement.(PER 115682)*One of four studs for 1-MVOP-074-0002, RHR Pump 1A Shutdown CoolingSuction Valve, yoke support lack full thread engagement. (PER 115502, WO 06-725880-000)*HVAC ducting discharge vanes for the 1C, 1B and 1D RHR pumps havenumerous vanes missing, loose or closed. (WO 06-725993-000)*A wall flange connection for support 1-47B45250172 in the Unit 1B and 1D RHRheat exchanger room on elevation 565 has broken grout and appears to have been pulled away from the wall. (PER 115716)*The support for fire hose station U-R2 (1A and 1B RHR pump room elevation541) has one of two bolts missing. (WO 06-725996-000)*The motor heater for RHR Pump 1A, 1-HTR-074-0005, is of a different designthan other RHR pump motors and does not sit flush on motor casing and the lock washers for the bolting flange are forced into their slots. (PER 115713) *Electrical conduit for 1-SHV-074-11 was pulled away from its associated limitswitch box. (WO 06-726023-000)13The inspectors performed an in-depth review of the SPOC testing package. Thefollowing deficiencies were noted:*Tool room issue ticket for 1-SR-3.5.1.6 (RHR I-COMP), RHR Loop IComprehensive Pump Test, performed on October 17, 2006, did not reflect all M&TE used during the test. The two gauges used for measuring the pump suction pressures, E34275 and E34274, were checked out for the Loop II test and not the Loop I test. In addition, instrument accuracy ratio calculations documented in the section 4.0, step [7], of the procedure for 1-SR-3.5.1.6 (RHR I-COMP) performed on October 17, 2006, and 1-SR-3.5.1.6 (RHR II-COMP)performed on October 17, 2006, contained mathematical errors and used incorrect gauge range and M&TE accuracy. (PER 115653)*Vibration acceptance criteria located in section 7.0 steps 29.2 & 50.2 of 1-SR-3.5.1.6(RHR II-COMP), RHR Loop II Comprehensive Pump Test, is not consistent with acceptance criteria in section 6.0.A.3. (PER 115668)*WO 05-716100-000, Form SPP-9.2-26, Environmental Qualification MaintenanceRecord, steps 20 (corrective actions) & 21 (foreman's signature) were not completed as required when further degradation was marked "yes" in step 17.

(PER 115673)The inspectors noted that the licensee issued PERs and/or WOs to address each of theabove deficiencies. b.4System 75, Core Spray (CS) System Readiness InspectionThe inspectors reviewed the SRTS-OIP including exceptions and deferrals, anddiscussed them with members of the TVA restart organization. The CS system had one exception and five deferral items which are planned to be completed prior to declaring the system operable. The exception item, documented as TVA punchlist number PL-06-3383, requires completion of DCN 51016 on the CS and the RHR systems. The Unit 1 DIV I Core Spray pump start permissive pump logic was at the time defeated by the installation of a jumper around the associated accident signal logic relay documented under WO 06-721313-000. The inspectors performed an in-depth system walkdown. All accessible portions of thesystem were inspected. The following deficiencies were noted and communicated to the licensee upon discovery: *An active red danger clearance tag was found on the floor of the Unit 1 controlroom panel crawl space. (PER 113863)*The Unit 1 control room panel crawl space contained transient combustiblesincluding safety glasses, working gloves, paper, plastic, and other debris. (PER 113860) *The 1B CS pump RTD for lower bearing temperature was missing terminalhousing cap. (WO 06-725675-000)14*Check valve 1-CKV-570C leakage has corroded body to bonnet stud fastener. (WO 06-723490-000)*Several MOVs (Valves 1-VTV-075-2, 1-DRV-075-11, 1-VLV-075-9) haveLimitorque limit switch cover fasteners that were missing or not fully engaged.

(PER 114052)*Test valve 1-TV-075-590 was partially open (normally shut) and possiblydamaged as seen in galled stem threads. (PER 114073)*The inspectors observed that Electric Board Rooms 1A and 1B had scaffoldingin overhead that could hinder smoke alarm initiation, fire fighting strategies and capabilities. Licensee Fire Operations evaluated the scaffolding and stated that fire fighting capabilities were not negatively impacted. Additionally, racked out breakers were not covered to prevent debris from entering their cubicle areas.

(PERs 112844 and 113210). The inspectors noted that the licensee issued PERs and/or WOs to address each of theabove deficiencies. Additionally, the inspectors performed a review of several testing packages completed for the Unit 1 recovery project and SPOC II completion. Overall, the inspectors determined that the selected sample of tests were performed in accordance with approved written procedures and properly documented. The inspectors traced a number of test deficiencies identified in test documents to the Browns Ferry Unit 1 SRTS-OIP. b.5System 85, Control Rod Drive (CRD) System Readiness InspectionThe SPOC II package had no exceptions and two deferrals which did not have to becompleted prior to declaration of operability. On December 14, 2006, prior to fuel loading, Operations declared the Unit 1 CRD system operable. The inspectors performed an in-depth system walkdown of all accesible areas. The following deficiencies were identified:Under Vessel Inspection*An FME cover was pulled away from one side of the equipment drain sump withdebris around the side and beneath the rod gallery carousel. (PER 116837)*Extensive use of tie wraps and duct tape on under-vessel structures weredetermined to be potential ECCS strainer clogging and stainless steel chloride stress corrosion cracking issues. (PER 116835)*Nuclear detector cable installations through drywell penetrations used tie wrapsto secure cables to mounting brackets. (PER 116835)*Three CRD housing support steel nuts had undersized washers, with a potentialto pull both washer and nut through the stud hole. (PER 116834)15CRD Walkdown Outside the Drywell*CRD Pump 1A outboard pump bearing oil reservoir was low (out of thesightglass). Unit operators were aware and WO 06-726825-000 had been previously initiated the day before to resolve the deficiency. However, operators did not appear to be aware of how rapidly oil was being lost. The reservoir required filling at least twice per shift.*CRD Pump 1A mechanical seal had a slow leak and a large amount of whatappeared to be metal shavings on the seal housing. (WO 07-710352-000)*CRD Pump 1B had some water with a little oil on the base of the pump betweenthe speed increaser and pump. The inspector identified several small oil leaks that included: motor outboard bearing oil lower sightglass, 1PI-085-0062B, speed increaser tubing 1TE-085-0006F, and CRD Pump 1B Speed Inc High Speed Gear Bearing. (WO 07-710353-000) *CRD Pump 1B had an oil and water leak on the outboard pump bearing/seal(WO 07-710353-000).*CRD Pump 1B, 1TE-0856-0006A appeared to be missing the cap. There wasduct tape covering the housing. (WO 07-710368-000)*Minor labeling inconsistencies were identified on breakers 1BKR-085-0002 and1BKR-085-0008 (Attachment 3) and valves 0DRV-085-0502 and 0DRV-085-0503 (Attachment 1) between labels and nomenclature (WO 07-710373-000)*CRD Hydraulic System Panel located in NE corner of the RB, elevation 565', hadseven gages with partially covered labels. (WOs 07-710388-000 and 07-710389-000)*Top of TIP room in RB, elevation 565, numerous cable trays had lots of trash inthem. Inspectors subsequently noted that licensee removed trash.Hydraulic Control Units (HCUs)*HCU 085-26-19 had a leak where solenoid Valve 1FCV-085-40C/2619 mountson the check valve. (WO 07-710375-000)*HCU 085-14-35 had two leaks on the top of accumulator water side and on1CKV-085-594/1435. (WO 07-710377-000)*HCU 085-22-59 had a leak where solenoid Valve 1FCV-085-40A/2259 mountson the check valve. (WO 07-710378-000)*HCU 085-58-23 Valve 1SHV-085-617/5823 had a body-to-bonnet leak. (WO 07-710380-000)16*HCU-085-46-19 Valve 1CKV-085-616/4619 was missing a body-to-bonnet bolt. (WO 07-710381-000)*HCU Module 54-19 scram inlet Valve, 1FCV-085-0039A has no positionindicator. (WO 07-710863-000)*HCU Module 38-55 root valve to PI 85-34 Valve, 1RTV-085-0229A has a bentstem. (WO 07-710866-000)*Valve 1VTV-085-0528A has a cap installed, but the cap is NOT shown onDrawing 0-47E820-1. (PER 118274)Valve Lineup Errors/Observations*Inspectors found Valve 1SHV-085-0556, Drive Water Filter 1A Inlet ShutoffValve, in the open versus closed position. (PER 116825)*CRD Module 50-19, Valve 1FCV-085-0039A, CRD Scram Inlet Valve, appearedto be in the intermediate position. (WO 06-726887-000).*On the lineup of record, Valve 1SHV-085-0559, Drive Water Filter 1A OutletShutoff Valve, was first and second checked for position, but neither the open nor closed positions were specified. (PER 118098)*Both stablizing valves inlet shutoff Valves, 1-SHV-085-0580 and 1SHV-085-0578, were closed on the valve lineup of record. The drawing showed one stablizing valve in service with the inlet valve open. (PER 116866)*Valve 1VTV-085-0582 does not have a cap installed as shown onDrawing 0-47E820-2. (WO 07-710385-000)*Valve 1DRV-085-0530A does not have a cap installed as shown onDrawing 0-47E820-1. (WO 07-710386-000)*Valve 1DRV-085-0511A does not have a cap installed as shown onDrawing 0-47E820-1. (WO 07-710387-000)During the above system walkdowns, the inspectors identified a significant number ofmaterial and/or administrative deficiencies which had not been previously identified during the licensee's walkdowns. Of special note were the CRD Pumps 1A and 1B which have both water (flanges, fittings, and pump mechanical seals) and oil leaks. The inspectors identified that the 1A outboard pump bearing oil bubbler was low (out of sightglass) and required filling twice per shift. Following three full scram actuations that occurred on December 19, 2006, the inspectors identified numerous water leaks on the hydraulic control units (HCUs). The inspectors noted that the licensee issued PERs and/or WOs to address each of the above deficiencies.

17The inspectors performed an in-depth review of the testing package completed for thesystem pre operability review, including reviews of 1-SR-3.3.1.1.12 (Mode Switch), 1-SR-3.3.1.1.13 (Scram Discharge Volume), and 0-TI-20 (Control Rods). No deficiencieswere noted.Reviews of design documents and calculations indicated there were no unverifiedassumptions applicable to the CRD System. However, BFN-50-7085, Design Criteria Document, Control Rod Drive System, Revision 12, Section 3.5.2, Item (9), indicated that a modification associated with both Units 2 and 3 may not have been performed on Unit 1. The inspectors discussed this observation with the system engineer who later verified that the modification was completed under DCN 51206. PER 118100 was issued to resolve this administrative error with the design criteria.The inspectors also reviewed the December 7, 2006, SRTS-OIP for System 85 CRD. Item 111 referenced WO 06-725548-000 which documented a problem with HCU 34-27 scram inlet and outlet valve diaphragms being inverted. That issue is further discussed in Section M1.1 of this report. b.6System 92, Neutron Monitoring System Readiness InspectionThe SPOC II package had three exceptions which must be resolved prior to adeclaration of operability is made for the Average Power Range Monitors (APRMs),

Oscillation Power Range Monitor (OPRM), and the Intermediate Range Monitors (IRMs). During the course of this inspection the Neutron Monitoring System experienced severalhalf and full scrams that required the installation of jumpers on the IRM system. The licensee entered the spiking of the IRMs into their corrective action program (PER 115955). Initial licensee investigation attributed these spikes to faulty rod position indication system power supplies or construction work activities. During subsequent investigation under WO 07-710482-000, the licensee determined the cause of IRM spikes (predominantly occurring on dayshift) to be mechanical agitation of two IRM wiring conduits located in separate high traffic areas within the drywell. The licensee will continue to monitor and evaluate IRMs under PER 117917. Jumpers were installed to prevent inadvertent scram signals and removed to allow control rod testing. The inspectors noted that the licensee issued PERs and/or WOs to address each of the above deficiencies.

b.7System 99, Reactor Protection (RPS) System Readiness InspectionInspectors reviewed the SRTS-OIP. The SPOC II package had one exception whichmust be cleared prior to declaration of operability. Punchlist open item PL-06-3509, was mis-coded, leaving the impression that it had been closed. The exception was adequately described in other properly coded open items. The system engineer corrected the error and assigned the proper code to the exception.All RPS components have been either refurbished or replaced with the plannedexception of portions of RPS wiring. The inspectors verified the refurbished and replaced components were in satisfactory condition. No deficiencies were noted.

18Inspectors reviewed the testing package for system pre-operability. Many of theacceptance criteria were only partially satisfied due to the RPS not being tested beyond the system boundary as defined by the licensee. Electrical jumpers were installed to allow partial testing of the RPS. The inspectors noted that planned post-SPOC II jumper removal and surveillance testing, inclusive of the interfacing systems, will allow the acceptance criteria to be fully satisfied. b.8System 43-01, Post Accident Sample (PASS) System Readiness InspectionThe SPOC II package for this partial system had no exceptions or deferrals. Theinspectors performed a system walkdown and noted that Root Valve, 1-RTV-043-0158A, installed in the C RHR HX was observed to be in the closed position. Per 1-TI-331,

"Post Accident Sampling Procedure," revision 0001, the normal position for this valve is open. The inspectors noted that the licensee issued PER 117167 to address this error. b.9System 03-01, Reactor Vessel Level Indication (RVLIS) System Readiness InspectionThe SPOC II Package for this partial system had no exceptions of deferrals. Theinspectors reviewed and evaluated PER 111131, 10CFR21 reported watchdog timer error for OTEK meters, for potential impact to RVLIS instrumentation. Inspectors verified that the affected OTEK HI-Q series instruments were not part of the limited RVLIS scope required for fuel load. The licensee's resolution of this generic instrumentation issue is discussed further in Section E8.8.

c. Conclusions

The inspectors noted that licensee management expectations were strengthened andbetter communicated resulting in increased ownership by operating ownership; increased operating organization participation in SPOC meetings, testing, and walkdowns; and systems being turned over in a much more ready condition resulting in fewer open items. System walkdowns, package reviews and interviews with licensee personnel indicated the above Unit 1 systems were adequately turned over as functional and/or operable systems with exceptions to operability and deferrals adequately annotated in the SPOC II System Return to Service - Open Item Punchlist. For CRD, although there were numerous minor material deficiencies, inspectors concluded that the Unit 1 CRD system was adequately turned over to Operations as a functional system without any exceptions and only a few deferrals. None of the material deficiencies would prevent the system from performing its required safety function.

System deficiencies are adequately documented in the Browns Ferry Unit 1 System Return to Service-Open Item Punchlist. However, inspectors will continue to review system turnover activities and observe future boards to verify the effectiveness of the turnover process associated with future safety-related systems.

19E1.3Area Turnover Activities (37550, 37551)

a. Inspection Scope

The licensee's process for turnover to the plant operations organization of Unit 1 areasafter construction activities were completed was reviewed. This program was previously reviewed as documented in Inspection Report 50-259/2006-07. Licensee management subsequently temporarily suspended turnover of plant areas due to problems with plant area readiness for turnover. The licensee had informed the inspectors that the area turnover process would not be resumed until Unit 1 management determined that the appropriate time had been reached to support resumption of area turnover activities.

The inspectors identified plant areas that contain selected risk-significant and safety-related equipment for independent NRC inspection and planned to continue inspection efforts to determine consistent program implementation and resolution of select punchlist items.The area turnover program was recently revived by the licensee. The licensee hasformally turned over a total of ten areas, all in the Reactor Building. Inspectors independently inspected these areas. Inspectors reviewed a recent revision of Business Practice BP-338, Area Turnovers from Recovery Unit 1 Restart Project. Additional document reviews included area turnover packages comprised of the remaining punch listed action items, unfinished scheduled work activities, and previous walkdown items.

Inspectors interviewed the program focal point of contact. Both independent plant area walkdowns and licensee walkdown observations were conducted by inspectors.

Independent inspector walkdowns were performed to focus on area deficiencies.

Observations of plant and restart management were performed to ensure licensee area turnover philosophy and methodology were consistent. The new area turnover schedule and status were reviewed for restart impact.

b. Observations and Findings

Inspectors identified numerous housekeeping issues, including debris (tape, string, wire,and cable ties) and tools left in the field following maintenance, as well as minor material condition issues (e.g., dirty sight glasses, missing screws, missing conduit and fire seallabels). Most issues were corrected immediately by the licensee. However, housekeeping issues in the reactor building elevation 621 and the shutdown board rooms were followed up with PER 118402. The inspectors questioned the adequacy of housekeeping controls once area responsibilities are assumed by the plant operating organization. However, based on discussions with the operating plant maintenance management the inspectors determined that weekly area walkdowns of these turned over areas are being conducted by licensee supervision in an attempt to maintain housekeeping, safety, and material standards. The licensee noted that they were also identifying numerous housekeeping and minor material issues and attributed them to continuing contract work in those areas.A generic concern identified by the inspectors involved Fire Fighting Pre-Fire Planswhich did not identify all installed equipment that is available (e.g., emergency lighting and fire dampers) and listed some equipment that is no longer installed or available (e.g., manual foam control station and AFFF foam tank). The licensee documented the 20need to update fire pre-plans into their corrective action program (PER 117818).Inspectors observed licensee management on initial area turnover walkdowns of bothSoutheast and Southwest corner rooms and determined that management walkdowns were being conducted as per BP-338. Subsequent to these walkdowns the licensee informed the inspectors that the Southeast corner room did not meet site standards for turnover and additional work was needed prior to another turnover walkdown being performed. Inspectors concurred with the licensee's conclusion. The inspectors also performed independent area walkdowns of several areas which hadcompleted the licensee's turnover process. During those walkdowns a number of deficiencies were identified which had not been identified by the licensee. Deficiencies identified by the inspectors included:Southeast Corner Room:The area turnover for this area was initially rejected by licensee management. Followingfinal acceptance of the area the inspectors performed an independent walkdown of the area and no significant deficiencies were noted.Northeast Corner Room:*541 elevation, no pipe caps on piping ends downstream of 1-PISV-085-0002B(Panel Isolation Valves to PI-85-2), 1-DRV-073-0725,1-DRV-073-0727. DRV-073-0727 handwheel not attached, hanging from valve body by lockwire.*541 elevation, lock and chain (not secured) hanging around pipe and valve 1-SHV-024-0732, RCW to CRD Pump 1A *541 elevation, lock and chain (not secured) hanging around pipe and valve 1-SHV-085-0512, CRD Pump 1A Shaft Seal Shutoff Valve*541 elevation, oil level in 'Outboard Bearing' bubbler for CRD Pump 1A low i.e.<1/4" visible in bubbler*541 elevation, electrical junction box - 1280 front cover open

• 519 elevation, lighting panel LS-200 front cover missing four screws

• 519 elevation, pressure regulator (IA) 1-PREG-077-0017 has cracked/brokengage glass*519 elevation, floor drain has dirt and debris inside adapter cover plate The inspectors noted that the licensee placed the above deficiencies in their correctiveaction program. (PER 115568)21Southwest Corner Room, 519 and 541 elevations:*Lockwire broken/missing for RHR Pumps 1A and 1C Suction Relief Valves, 1-RFV-074-0509A and 1-RFV-074-0509C. (PER 115691)*The Pre-Fire Plans did not list some equipment available, and listed someequipment not available. (PER 117818)*The drain sump ventilation hose was attached to the ventilation pipe with ducttape which was brittle. The inspectors noted that the licensee subsequently replaced the brittle duct tape andissued PERs to address the other two above issues.Northwest Corner Room, 519 and 541 elevation: The inspectors observed that the radiation monitor detector cable insulation had beenpulled from the connector. (PER 118398)Torus Room:*24 Electrical junction boxes were found to have inadequate sealing as per BFNprocedures. (PER 117822)*Numerous housekeeping issues were addressed, including water seepage andsurface corrosion evaluations, graffiti and mislabeling. (PER 113545)*A jackscrew was wedged between the structural concrete wall and the ringheader in order to support a ladder without an engineering evaluation. (PER 117819)*The 1B RHR drain pump outboard bearing oil reservoir was very low. Theinspectors noted that operations subsequently added oil to the reservoir.The inspectors noted that the licensee issued PERs to address the other three aboveissues.Reactor Building 593 Elevation, B 4KV Shutdown Board Room:Disconnect hot stick ID# E13775 was found past it's inspection date expiration and wasnot included in the licensee's preventive maintenance database. (PER 118433).Reactor Building 621 Elevation, A 4KV Shutdown and A/B 480V Board Rooms:*Inspectors were unable to inspect material conditions in the overhead due toinstalled scaffolding for continuing work in progress.*Two unsecured ladders were hanging from a rack at the R2-R line. Drawings 0-48E909-1, 0-48E909-3, and 0-48E909-6 indicated the rack was designed to hold 22only one ladder and that the ladder was required to be secured with a padlock. (PER 118403)Reactor Building 621 Elevation:Portable radiation survey instrument (serial number 33761) located on top of the FuelPool Cooling annunciator network panel was past the calibration due date. (PER 118593)

c. Conclusions

Area turnover guidance and the quality of turnover packages submitted to walkdownparticipants were adequate. However, the inspectors determined that, with 20% of planned area turnovers complete, areas are being turned over with Unit 1 restart work still outstanding. Outstanding work and other deficiencies continue to be identified by restart area coordinators and plant management during walkdowns and subsequently punch listed as in the same process for SPOC II system turnover. The NRC intends to continue inspection efforts of selected areas to determine consistent program implementation and resolution of select punchlist items. The inspectors determined that activities associated with the Unit 1 restart area turnover process did not cause any significant impact to the operability of equipment required to support operations of Units 2 and 3. No violations or deviations were identified.E1.4System Restart Testing Program Activities (37551, 35301, 70304, 70315)

a. Inspection Scope

The inspectors reviewed and observed on-going Restart Test Program (RTP) activitiesassociated with system acceptance testing for seven risk significant systems to ensure activities were in compliance with design basis requirements. Additionally, the inspectors reviewed the activities associated with the RTP TestSummary Reports (TSR) for six risk significant systems. The reviews were performed to verify that the individual systems would be capable of supporting safe down and maintain shutdown of the Unit 1 reactor.

b. Observations and Findings

b.1System Acceptance Testing ActivitiesRestart testing activities reviewed and observed consisted of system acceptance testingperformed on System 57-5, 4160V AC Distribution; System 64B, Reactor Building and Primary Containment Ventilation; System 70, Reactor Building Closed Cooling Water (RBCCW); System 71, Reactor Core Isolation Cooling (RCIC); System 74, Residual Heat Removal (RHR); System 85, Control Rod Drive (CRD); and System 99, Reactor Protection (RPS). Additionally, the inspectors reviewed and observed selected Emergency Core Cooling System (ECCS) logic initiation tests.

23Test procedures consisted of Post Modification Test Instructions (PMTIs) issued to testportions of applicable DCNs, Technical Instructions (TIs), and Surveillance Instructions (SIs) and Surveillance Requirements (SRs). The inspectors verified that pre-test briefings were held, assignments made, and communications were established prior to performance of testing. The inspectors also attended various meetings where testing activities, test planning, testing status, test exceptions, and test results were discussed.

The inspectors observed portions of the ongoing testing, reviewed selected completed test packages, and verified acceptance criteria for testing were satisfied. Specific system acceptance testing activities reviewed and observed included the following:RBCCW System acceptance testing associated with RBCCW reviewed and observed included:*1-SI-3.2.31, the purpose of this test was to perform the ASME Section XIrequired testing of check valves in the system. *1-SI-4.7.A.2g-3/70, the purpose of this test was to perform the Local leak RateTest (LLRT) of flow control valve 1-FCV-70-47 and check valve 1-CKV-70-506. *1-TI-516, Water Flow Balance, the purpose of this test was to verify that eachcomponent in the system received their designed cooling water flow, such as the System 68, Reactor Recirculating Pump oil coolers, the System 69, RWCU, non-regenerative heat exchangers, and the System 64B, Ventilation, drywell coolers.*MI ECI-0-000-MOV009 and WO 05-722083-01, the purpose of this test was toperform MOVATS and stroke time testing of selected system valves. System testing determined the operability of the RBCCW System was in conformancewith Technical Specification requirements for pump performance, flowpath verification, piping integrity, initiation logic, and ASME inservice testing. The inspectors observed selected portions of the ongoing testing, reviewed test results, and verified testing successfully fulfilled testing requirements.

RHR System acceptance testing associated with RHR reviewed and observed included:*1-SR-3.3.5.1.6(A I), 1-SR-3.3.5.1.6(AII), 1-SR-3.3.5.1.6(BI), 1-SR-3.3.5.1.6(BII),1-SR-3.3.5.1.6(CI) and 1-SR-3.3.5.1.6(CII); the purpose of these tests were to demonstrate that the RHR pumps receive an automatic start signal from the LPCI Emergency Core Cooling System (ECCS) logic system on high drywell pressure and a low RPV pressure signal.*1-SR-3.5.1.9(RHR I) and 1-SR-3.5.1.9(RHR II); the purpose of these tests wereto demonstrate that a valve close signal was provided to the recirculating pump discharge valves on a LPCI logic system, ECCS, when the RPV pressure was lower than the setpoint.

24*1-SR-3.3.5.1.2(ATU A), 1-SR-3.3.5.1.2(ATU B), 1-SR-3.3.5.1.2(ATU C), and 1-SR-3.3.5.1.2(ATU D); the purpose of these tests were to demonstrate that the RHR pumps receive an automatic start from the LPCI logic system, ECCS, on a low RPV pressure signal, and that LPCI injection valves do not receive an open signal until receipt of the low RPV pressure permissive signal.*1-SR-3.3.5.1.5 (DWP A-ECCS), 1-SR-3.3.5.1.5 (DWP B-ECCS), 1-SR-3.3.5.1.5(DWP C-ECCS), and 1-SR-3.3.5.1.5 (DWP D-ECCS); the purpose of these tests were to demonstrate that the LPCI logic system, ECCS, is a one-out-of-two-taken twice logic network and that the LPCI initiation logic was still present when one of the four inputs was removed.*1-SR-3.3.5.1.4(A), 1-SR-3.3.5.1.4(B), 1-SR-3.3.5.1.4(C), and 1-SR-3.3.5.1.4(D);the purpose of these tests were to demonstrate that the LPCI initiation logic was no longer present when both inputs for Channel A and both inputs from Channel B were removed.*1-SR-3.5.1.6 (RHR I-COMP), and 1-SR-3.5.1.6 (RHR II-COMP); the purpose ofthese tests were to demonstrate the following: Each individual RHR pump delivered the rated ECCS flow for LPCI of 10,800 gpm; two RHR pumps, for each loop, delivered the rated ECCS flow for LPCI of 20,000 gpm; and the minimum flow valves closed at the required setpoint.*1-SR-3.3.5.1.5 (LPCI I), 0-SR-3.8.1.8(I) and 0-SR-3.8.1.8(II), the purpose ofthese tests and other tests were to demonstrate the following: Torus cooling and spray flows were adequate; interlocks such as suction valves being open, pumps running, and power available functioned as required; and signals were sent to other systems such as ADS.System testing determined the operability of the RHR System was in conformance withTechnical Specification requirements for pump performance, flowpath verification, piping integrity, initiation logic, and ASME inservice testing. The inspectors observed selected portions of the ongoing testing, reviewed test results, and verified testing successfully fulfilled testing requirements.

CRDSystem acceptance testing associated with CRD reviewed and observed included:

• 1-TI-186, the purpose of this test was to demonstrate that a SCRAM signal fromthe RPS activated the SCRAM pilot valves, closed the Scram Discharge Volume (SDV) vent and drain valves, and all rods were inserted.*1-SR-3.3.1.1.12, 1-SR-3.1.4.1,and PMTI-51080, the purpose of these tests wereto demonstrate that a loss of power to the RPS activated the SCRAM pilot valves, closed the SDV vent and drain valves within the specified times, all rods were inserted within the specified times, and indication was provided in the Main Control Room (MCR).

25*1-SR-3.3.2.1.1 and 1-SR-3.9.1.1, the purpose of these tests were todemonstrate that a rod block interlock signal from the Rod Block Monitor and the fuel handling system, the Reactor Manual Control system prevented a control rod withdrawal.*0-SI-4.3.B.2. the purpose of this instruction was to inspect the CRD housingsupport structures after reassembly.*0-TI-20, the purpose of this instruction was to demonstrate the following: TheMCR indication for each control rod indicated the correct rod selected, latch position, mid position, full-in and full-out, and inserted over travel position. *1-SR-3.3.1.1.13. the purpose of this test was to demonstrate that the levelswitches in the scram discharge instrument volume provided, in order, an alarm condition in the MCR, a rod block in the CRD system, and a SCRAM. *1-SR-3.3.4.2.4, and WO 06-724057-00. the purpose of these tests were todemonstrate that an Alternate Rod Insertion (ARI) was provided through the ATWS system on a RPV low water level or a RPV high pressure signals.System testing determined the operability of the CRD System was in conformance withTechnical Specification requirements for pump performance, flowpath verification, piping integrity, initiation logic, and ASME inservice testing. The inspectors observed selected portions of the ongoing testing, reviewed test results, and verified testing successfully fulfilled testing requirements.

RPSDue to the condition of the various systems inter-connected with the RPS the testingperformed did not include inputs/outputs from these systems. Consequently only partial testing was performed on the internal RPS logic. Testing reviewed and partially observed for this system included the following:*1-SR-3.3.1.1.14(5I), 1-SR-3.3.1.1.14(5II), 1-SR-3.3.1.1.14(8I) and 1-SR-3.3.1.1.14(8II); 1-SR-3.3.1.1.10(3A), 1-SR-3.3.1.1.10(3B), 1-SR-3.3.1.1.10(3C),

and 1-SR-3.3.1.1.10(3D); 1-SR-3.3.1.1.13(4A), 1-SR-3.3.1.1.13(4B), 1-SR-3.3.1.1.13(4C), and 1-SR-3.3.1.1.13(4D); 1-SR-3.3.1.1.13(6A), 1-SR-3.3.1.1.13 (6B), 1-SR-3.3.1.1.13 (6C), and 1-SR-3.3.1.1.13 (6D); 1-SR-3.3.1.1.13; and 1-SR-3.3.1.1.16. the purpose of these tests were to demonstrate that the RPS logic responded by providing a SCRAM as required for such inputs as MSIVs in selected pairs closed, low hydraulic fluid pressure on the fast acting main turbine control valves, main turbine stop valves in selected pairs closed, high RPV pressure, low RPV water level, high neutron flux level, high drywell pressure, and high water level in the SDV. These test also demonstrated that the manual re-set was inhibited for 10 seconds following a SCRAM and that the SCRAM response was less than 50 milliseconds.

26*PMTI-51080 and 1- SR-3.3.1.1.8(11). the purpose of these tests were todemonstrate that manually opening both RPS MG setoutput breakers initiated a FULL SCRAM, manually pressing either manual SCRAM switches initiated a HALF SCRAM, manually pressing both manual SCRAM switches initiated a FULL SCRAM, placing the reactor mode switch in the SHUTDOWN position initiated a FULL SCRAM, and the RPS can be de-energized from outside the MCR.*1-SR-3.9.1.1. the purpose of this test was to demonstrate that placing thereactor mode switch in the REFUEL position enabled the refuel interlock between the Reactor Manual Control System and the Fuel Handling System.*1-SR-3.3.6.1.2 (ATU A), (ATU B), (ATU C), and (ATU D) the purpose of thesetests were to demonstrate that the RPS provided a MSIV closure permissive to the PCIS with the mode switch in the RUN position. *1-SR-3.3.1.1.8(8); 1-SR-3.1.1.9(9); 1-SR-3.3.4.1.4; and 1-SR-3.3.1.1.15 (A1),(A2), (B1), and (B2) the purpose of these tests were to demonstrate that the RPS provided a signal to the Reactor Recirculating Pump Motor switchgear logic from the main turbine control valve fast closure, the main turbine stop valve closure, and the valve closure bypass, based on first stage pressure, at < 30%.*1-SR-3.3.1.1.13 (4A), (4B), (4C), and (4D); and 1-SR-3.3.1.1.13 (6A), (6B), (6C),and (6D) the purpose of these tests were to demonstrate that the RPS provided trip signals to the PCIS on low RPV water level and high drywell pressure.*1-SR-3.3.1.1.12, Reactor Protection System Mode Switch in Shutdown Scramand Logic System Functional Test determined the operability of the RPS system in conformance with Technical Specification requirements for mode switch performance, initiation logic, and interfacing annunciation and rod block logic.

During the ongoing testing the inspectors observed that the test director, a licensed reactor operator, manually re-initiated channel A ARI (Alternate Rod Insertion) per 1-SR-3.3.1.1.12, step 34, upon the request of an engineering management representative to gather parallel information via a work order. The test director did not discuss the bases of the re-initiation with the testing team nor his immediate supervision. This apparent lapse of cognizant control by the test director was discussed with operations and engineering management and recognized as an opportunity for improvement. The plant had been placed in a safe condition prior to and following the re-initiation.Additionally the inspectors observed a red danger tag affixed to control roompanel 1-9-5 adjacent to the Mode Switch. The tag did not have a designated switch position. Review of the clearance 1-001-0002A indicated the tag was to prevent the mode switch from being placed in the START or RUN positions when fuel is present in the reactor vessel. The switch could be placed in any position prior to loading fuel. Review of SPP-10.2, Clearance Procedure to Safely Control Energy, indicated the site procedure was silent on using a danger tag in this manner. Discussions with licensee operations management indicate they will evaluate their site expectations against other corporate sites and either justify 27current philosophy or adequately disposition. The licensee has entered this intotheir corrective action program. (PER 117580)System testing determined the operability of the RPS System was in conformance withTechnical Specification requirements for initiation logic. The inspectors observed selected portions of the ongoing testing, reviewed test results, and verified testing successfully fulfilled testing requirements.

ECCS Logic TestingECCS logic test procedures were developed, written, approved, and issued to test theinitiation logic of the RHR and Core Spray (CS) Systems. The various logic tests of these systems that were reviewed and observed are separately documented above, in Section E1.4.b.2 of this report, and in Inspection report 05000/259/2006-08. The types of tests involved mechanical, electrical, and I & C equipment. The inspectors observed selected portions of the ongoing logic testing, reviewed test results, and verified testing successfully fulfilled testing requirements.

RCIC1-SR-3.5.3.4, RCIC System Rated Flow at Low RPV Pressure determined theoperability of the RCIC turbine, pump, and auxiliaries in conformance with Technical Specification requirements for rated flow and pressure at auxiliary boiler steam pressure (150-165 psig) and also verification of backup flow control transfer. The inspectors observed the ongoing testing, reviewed test results, and verified testing successfully fulfilled testing requirements.

Diesel Generator Load Acceptance TestingIn addition to the tests documented above, the inspectors observed and reviewed on-going RTP test activities leading up to and including diesel generator load acceptance testing to evaluate compliance with design basis requirements. Inspectors observed various pre-job briefs, and in-process (testing) and post-job discussions between craft and engineers. Inspectors also attended various meetings where testing activities, test planning, testing status, test exceptions, and test results were discussed. Inspectors observed portions of the ongoing testing, reviewed selected completed test packages, and verified acceptance criteria for testing were satisfied.The test procedures were Surveillance Requirements (SRs) issued to verify functionalityand determine operability in conformance with Technical Specification requirements.

The inspectors verified pre-test briefings were held, assignments made, and communications were established prior to test performance. The inspectors also verified adequate configuration control through updated plant documents, drawings, and procedures, and confirmed satisfactory test results. In addition, special emphasis was placed on the potential impact of testing activities on operability and availability of equipment required to support operations of Units 2 and 3. Selected testing activities reviewed and observed included the following:

28*0-SR-3.8.1.9 (A), Diesel Generator A Emergency Unit 1 Load Accept Test; and0-SR-3.8.1.9 (C), Diesel Generator C Emergency Unit 1 Load Accept Test. The purpose of this test was to demonstrate that the diesel generator was capable of accepting the Unit 1 emergency loads assigned to the generator. The test was performed satisfactorily. In reviewing the completed test package, inspectors noted that personnel didnot properly document the as left position of the RWCU Demin Holding Pump 1A breaker, nor was it identified by the independent verifier. (PER 114721)*0-TI-533, Diesel Generator B Emergency Unit 1 Load Accept Test; and 0-TI-534,Diesel Generator D Emergency Unit 1 Load Accept Test. The purpose of this test was to demonstrate that the diesel generator was capable of accepting the Unit 1 emergency loads assigned to the generator. The test was performed satisfactorily.*0-SR-3.8.1.6, Common Accident Signal Logic Test, determined the operability ofthe Unit 1 and 2 diesel generators in conformance with Technical Specification requirements for automatic starting from a standby condition with accident signals. During the ongoing testing the inspectors identified and informed licensee management that requirements for double "booting" electrical relay contacts during logic testing was not discussed in the precautions and limitations of appropriate logic tests, including this test. (PER 116801)Inspectors observed test support personnel not using proper peer checking andflagging human performance tools while installing a test switch in Unit 2 Auxiliary Instrument Panel. (PER 114679)The inspectors observed the ongoing testing, reviewed test results, and verified testingsuccessfully fulfilled testing requirements.

b.2Test Summary Reports (TSRs)The TSR's were developed, written, approved, and issued to document the results oftests performed on the listed systems. The tests verified that the system performed adequately to the specified design functions. The tests were based on the system Baseline Test Requirement Documents (BTRD) Modes. The system BTRD's were based on the safe shutdown analysis (SSA) and were used to establish test requirements (by system mode) to verify all safe shutdown functions. During this reporting period the inspectors reviewed TSR's on tests performed on System 24, Raw Cooling Water (RCW); System 57-5, 4KV Distribution; System 64B, Reactor Building Ventilation System (RBVS); System 70, Reactor Building Closed Cooling Water (RBCCW); System 74, Residual Heat Removal (RHR); System 85, Control Rod Drive; and System 99, Reactor Protective System (RPS). Specific TSRs reviewed included the following:

294KV AC Distribution, TSR 1-BFN-BTRD-575 The 4KV AC Distribution System consisted of seven BTRD Modes as follows:*Mode 575-01, Provide Class 1E 4KV power distribution. Testing for this modehad been previously performed and documented during the Unit 2 recovery which had verified Diesel Generators A, B, C, and D started automatically; all applicable 4KV pump motor feeder breakers fed from the 4KV power distribution Shutdown Boards A, B, C, and D received trip signals upon loss of voltage; all 480V loads on the 480V Shutdown Boards 1A, 1B, 2A, and 2B that load shed onvoltage tripped if they were closed when the test was initiated; and transformer loads on the 4KV Shutdown Boards A, B, C, and D remained connected to the board without tripping when the test was initiated.*Mode 575-03, Provide instrumentation for DG paralleling. Testing for this modehad been previously performed and documented during the Unit 2 recovery which had verified Diesel Generators A, B, C, and D were paralleled with the grid from the MCR and from the Units 1 and 2 Shutdown Boards A, B, C, and D; the DG's A, B, C, and D were paralleled with the Unit 3 DG's from the MCR and from the Units 1 and 2 Shutdown Boards A, B, C, and D; and the Unit 3 DG's were paralleled with the Units 1 and 2 DG's from the MCR and from the Units 3 Shutdown Boards 3EA, 3EB, 3EC, and 3ED.*Mode 575-04, Provide initiation signals to the DG's: Testing for this mode hadbeen previously performed and documented during the Unit 2 recovery which had verified the initiation signals consisted of a loss of voltage, an undervoltage condition, and a degraded voltage condition; with each shutdown board having independent detectors, each board and each type of detection were tested separately; the loss of voltage and the undervoltage condition started the DG's, load shedded the boards, and loaded the DG's; the degraded voltage condition started the DG's without load shedding and without loading the DG's. Since the original tests were performed, the Unit 1 inputs to the Common Accident Signal (CAS) were removed from service. DCN 51016, Emergency Core Cooling System (ECCS) Accident Signal Logic, restored these inputs, which required further testing. The tests required included 0-SR-3.8.1.6, Common Accident Signal Logic, and the DG load acceptance tests.

• Mode 575-06, Provide backup control for the 4KV feeder breakers outside thecontrol bay. The backup controls allow for control of the shutdown board breakers if the MCR has to be abandoned. Testing for this mode had been previously performed and documented during the Unit 2 recovery and the following was verified: The controls for the shutdown board breakers was transferred from the MCR to the applicable shutdown board; after the transfer there was no control/indication from the MCR; all related breakers were operated locally at the applicable shutdown board; the controls were transferred back to the MCR; and after the transfer back to the MCR there was no control at the applicable shutdown board.

30*Mode 575-07, Provide 4KV load shed and load sequencing logic. Testing for portions of the mode had been previously performed and documented during the Unit 2 recovery by test procedure 2-BFN-RTP-57-5, 4KV Distribution which had verified sustained bus undervoltage signals, degraded bus voltage signals, Loss of Coolant Accident (LOCA) with DG's providing power; and load sequencing of pre-selected loads upon receipt of a LOCA with DG's providing power. Since the original tests were performed, the Unit 1 inputs to the CAS were removed from service. DCN 51016, restored these inputs, which required further testing. The more recent testing included 0-SR-3.8.1.6, Common Accident Signal Logic, and the DG load acceptance tests. *Mode 575-08, Provide DG voltage available signal to accident signal initiated 480V load shed logic. Testing for portions of the mode had been previously performed and documented during the Unit 2 recovery by test procedure 2-BFN-RTP- 57- 4, 480V Distribution. Additional more recent testing for Unit 1 recovery included 0-SR-3.8.1.8(I), 480V Load Shed Logic System Functional Test (Division I); 0-SR-3.8.1.8(II), 480V Load Shed Logic System Functional Test nd (Division II); 1-ETU-SMI-1-48SDA, Procedure for Relay Functional Checks on 480V Shutdown Board 1A; 1-ETU-SMI-1-48SDB, Procedure for Relay Functional Checks on 480V Shutdown Board 1B. *Mode 575-09, Provide 4KV power distribution from off-site power. Testing forthis mode had been previously performed and documented during the Unit 2 recovery which verified that the Shutdown Buses 1 and 2 transferred from the normal to the alternate source with a loss of power to the normal source; the Shutdown Boards transferred from the normal to the alternate source with a loss of power to the normal source; the Unit Boards transferred from the normal to the alternate source with a loss of power to the normal source; Common Boards transferred from the normal to the alternate source with a loss of power to the normal source; a block of the Shutdown Boards transfer from the normal to the alternate source was present upon a receipt of an accident signal; the Shutdown Boards provided auto start signals to the safe shutdown loads under all required conditions; and the controls for the Shutdown Busses were transferred from the MCR to the Shutdown Busses.The inspectors reviewed the TSR and verified that the above 4KV Distribution systemmodes were satisfactorily tested during the ongoing testing activities. For Modes 575-01, 575-3, 575-6, 576-7, 576-8, and 575-9 where the licensee had relied on testing performed during the previous Unit 2 Recovery the inspectors concurred that no further testing of System 575 was required for Unit 1 recovery.Reactor Building Ventilation System (RBVS) TSR 1-BFN-BTRD-64BThe RBVS consisted of three BTRD Modes as follows:

• Mode 64B-23, Provide forced air cooling for the RHR, System 74, pump motors,and the Core Spray, System 75, pump motors at the required air flow. Testing for this mode was performed in conjunction with surveillance procedures 1-SR-3.5.1.6 (RHR I-COMP), RHR Loop I Comprehensive Pump Test; 1-SR-3.5.1.6 31(RHR II-COMP), RHR Loop II Comprehensive Pump Test; 1-TI-134, MeasuredAir Flow and Fan Motor Run Current Tests for RHR and Core Spray Pump Coolers; and 1-SR-3.5.1.6 (CS I-COMP), Core Spray Loop I Comprehensive Pump Test; 1-SR-3.5.1.6 (CS II-COMP), Core Spray Loop II Comprehensive Pump Test.*Mode 64B-27, Provide for a containment isolation upon a Primary ContainmentIsolation System (PCIS), System 64D, Group 6 isolation signal with the required valves and dampers to either close or remain closed. This mode also required that the applicable valves and dampers close on a loss of power and on a loss of control air. Test requirements for this Mode was satisfied by other testing associated with 1-BFN-BTRD-064A, Primary Containment System (PCS),

System 64A.*Mode 64B-28, Provide for containment isolation actions such as a trip of variousrequired ventilation fans, close applicable dampers, and open dampers to the Standby Gas Treatment System (SGTS), System 65. These actions were required to occur on a PCIS Group 6 isolation signal. Testing for this mode was satisfied by other testing performed on the Units 2 and 3 PCIS.The inspectors reviewed the TSR and verified that the above 4KV Distribution systemmodes were satisfactorily tested during the ongoing testing activities. For test requirements associated with Modes 64B-27 and 64B-28 which were satisfied by other testing the inspectors concurred that no further testing of System 64B was required for Unit 1 recovery.RBCCW, TSR 1-BFN-BTRD-70RBCCW consisted of three BTRD Modes as follows:

• Mode 70-01, Provide Primary Containment pressure boundary. Testrequirements for this mode was satisfied by other testing associated with System 64A, Primary Containment, BTRD. No further testing of System 70 was required for Unit 1 recovery to verify this mode.*Mode 70-02, Provide Secondary Containment pressure boundary. Testrequirements for this mode was satisfied by other testing associated with System 64C, Secondary Containment, BTRD. No further testing of System 70 was required for Unit 1 recovery to verify this mode. *Mode 70-03, Provide Drywell cooling when power and cooling water areavailable. Testing for this mode was performed and documented using Post Modification Test Instructions (PMTI), Technical Instructions (TI), Work Orders (WO), Surveillance Instructions (SI) and Maintenance Instructions (MI). Specific testing included PMTI-51090-STG12, 32, 55, and 56, Functional test of Drywell Blower load sheds, time delay relay settings, inhibit switches, and alarm circuits;PMTI-51195, functional test of DCN 51195 sectionalizing valves and DCN 51107 for Main Control Room CRDR tasks related to System 70; 1-SI-3.2.31, ASME Section XI test of check valve 1-CKV-70-506; MI ECI-0-000-MOV009 and WO 3205-722083-01 for MOVATS and stroke time testing of valve 1-FCV-70-47. Dueto the current conditions of the system some of the tests did not meet the initial condition requirements for starting the drywell blowers and performing 1-TI-199, Drywell Air Flow Balancing; and verifying the ability of the cooling system for the drywell atmosphere to maintain the design conditions in the drywell during operating conditions by performing 1-TI-082, Average Drywell Temperature.

Consequently, Punch List (PL) items (PL-06-2855 and 2858) were issued to track the testing until initial conditions can be met. Further testing for Unit 1 recovery of System 70 for this mode will be tracked by the PL items.The inspectors reviewed the TSR and verified that, with the exception of Mode 70-03testing which was deferred as discussed above, the above RBCCW system modes were satisfactorily tested during the ongoing testing activities. For test requirements associated with Modes 70-01 and 70-02 which were satisfied by other testing the inspectors concurred that no further testing of System 64B was required for Unit 1 recovery.RHR, TSR 1-BFN-BTRD-74RHR consisted of 20 BTRD Modes as follows:

• Mode 74-01, Supply RHR low pressure cooling injection (LPCI) water to thereactor vessel on automatic initiation on RPV low water level, Level 1, or high drywell pressure concurrent with low RPV pressure permissive signal, and manual LPCI initiation from the MCR. Testing for this mode consisted of nine requirements. Testing was either fully satisfied or partially satisfied by 1-SR-3.3.5.1.6(A I), (AII), (BI), (BII), (CI) and (CII); 1-SR-3.5.1.9(RHR I) and (RHR II);

1-SR-3.3.5.1.2(ATU A), (ATU B), (ATU C), and (ATU D); 1-SR-3.3.5.1.5 (DWP A-ECCS), (DWP B-ECCS), (DWP C-ECCS), and (DWP D-ECCS); 1-SR-3.3.5.1.4(A), (B), (C), and (D); 1-SR-3.5.1.6 (RHR I-COMP), and (RHR II-COMP); and 1-SR-3.3.5.1.5 (LPCI I). Testing consisted of verification that a LPCI initiation signal on high drywell pressure concurrent with low RPV pressure provided a start signal to the RHR pumps and an open signal to the injection valves, 1-FCV-74-53 and 67; verified that a LPCI initiation signal on low RPV level, Level 1, provided a start signal to the RHR pumps and did not provide an open signal to the injection valves until receipt of the low RPV pressure permissive; verified that a LPCI initiation signal provided a close signal to the System 68, Reactor Recirculation, pump discharge valves, 1-FCV-68-03 and 79, at the required RPV pressure setpoint; verified that the LPCI initiation signal is a one-out-of-two-taken-twice logic arrangement by removing one of the four inputs and the LPCI initiation signal was still present, and that the initiation signal was no longer present when both inputs to Channel A and both inputs to Channel B were removed; verified that the various required components, such as valves and pumps, align to the LPCI Mode on auto or manual initiation from their pre-initiation alignment, such as testing, standby, and shutdown cooling; verified that all four RHR pumps start sequence began immediately with normal AC power, and began immediately when diesel power became available; verified that various valves, such as pump suction, Torus suction, and injection valves open and/or closed in response to various system conditions such Group 2 PCIS 33signal, injection valves closed if shutdown cooling valves were not full open,valves did not open when RPV pressure was above setpoint, and pumps did not start when suction valves were not full open; and verified that various valves opened, or closed, and opened and closed within the required times. Due to the current configuration of the system some of the testing did not meet the initial condition requirements. Consequently, three Punch List (PL) items, PL-06-3589, 3572 and 3579 were issued to track the testing until initial conditions can be met. Further testing for Unit 1 recovery of System 74 for this mode will be tracked by the PL items.*Mode 74-02, Provide suppression pool water cooling to maintain suppressionpool water temperature below limits to assure adequate pump NPSH and that complete condensation of blowdown steam from a design basis LOCA can be expected. This mode contained two individual requirements. Testing for this Mode was fully satisfied by procedures 1-SR-3.5.1.6(RHR I - COMP) and 1-SR-3.5.1.6(RHR II - COMP) and consisted of verification that each pump in each loop delivered the rated LPCI flow of greater than or equal to 10,800 gpm with the reactor vessel to primary containment differential pressure equal to 0 psid; and verified that the two pumps in each loop delivered the rated LPCI flow of greater than or equal to 20,000 gpm with the reactor vessel to primary containment differential pressure equal to 0 psid. No further testing of System 74 was required for Unit 1 recovery to verify this mode.*Mode 74-03, Provide spray cooling water to the drywell and Torus forcontainment cooling and lowering of containment pressure. This Mode contained two individual requirements. Testing for this Mode was fully satisfied by procedures 1-SR-3.6.2.5.2(I), 1-SR-3.6.2.4.2, and 1-SR-3.6.2.5.2(II), and consisted of verification that the Torus spray piping, nozzles, and components were capable of performing the spray function by providing unimpeded water flow; testing of the pumps at specified flow rates verified adequate floe capacity; and verified that the drywell spray piping, nozzles, and components were capable of performing the spray function by providing unimpeded water flow. No further testing of System 74 was required for Unit 1 recovery to verify this mode. *Mode 74-04, Provide shutdown cooling manual mode to restore reactortemperature to normal. Test requirements for this mode was satisfied by other testing associated with System 74, RHR, BTRD, Mode 01 testing. No further testing of System 74 was required for Unit 1 recovery to verify this mode.*Mode 74-09, Provide Secondary Containment pressure boundary. Testrequirements for this mode was satisfied by other testing associated with System 64C, Secondary Containment, BTRD. No further testing of System 74 was required for Unit 1 recovery to verify this mode. *Mode 74-10, Provide Reactor Coolant pressure boundary. Test requirements forthis mode was satisfied by other testing associated with System 68, Reactor Recirculation System, BTRD. No further testing of System 74 was required for Unit 1 recovery to verify this mode.

34*Mode 74-11, Provide Primary Containment pressure boundary. Testrequirements for this mode was satisfied by other testing associated with System 64A, Primary Containment, BTRD. No further testing of System 74 was required for Unit 1 recovery to verify this mode.*Mode 74-12, Provide a logic signal to System 01, Main Steam, that an RHRpump is running for the Automatic Depressurization System (ADS) initiation logic. This mode contained one requirement. Testing for this mode was fully satisfied by procedures 1-SR-3.3.5.1.3(ADS A/RHR) and (ADS B/RHR), and verified that the pump pressure switches provided a running permissive signal to the ADS by closing the switch contacts when the loop detected the setpoint pressure. No further testing of System 74 was required for Unit 1 recovery to verify this mode.*Mode 74-14, Provide RHR System flow path for transmission of System 02,Demineralized Water and Condensate, water supply to System 73, HPCI, piping upstream of the HPCI pumps. Test requirements for this mode was satisfied by other testing associated with System 73, HPCI, BTRD. No further testing of System 74 was required for Unit 1 recovery to verify this mode.*Mode 74-15, Provide RHR System piping flow path from System 73, HPCI, pumpminium flow bypass line to System 64A, Primary Containment, suppression pool.

Test requirements for this mode was satisfied by other testing associated with System 73, HPCI, BTRD. No further testing of System 74 was required for Unit 1 recovery to verify this mode.*Mode 74-16, Provide RHR System piping flow path from System 71,RCIC, pumpminium flow bypass line to System 64A, Primary Containment, suppression pool.

Test requirements for this mode was satisfied by other testing associated with System 71, RCIC, BTRD. No further testing of System 74 was required for Unit 1 recovery to verify this mode.*Mode 74-17, Provide an automatic LPCI mode initiation signal to System 68,Reactor Recirculation System, to close the recirculating pump discharge valves. Test requirements for this mode was satisfied by other testing associated with System 74, RHR, BTRD, Mode 01 testing. No further testing of System 74 was required for Unit 1 recovery to verify this mode.*Mode 74-19, Provide manual RHR operation of the LPCI, Torus cooling, andshutdown cooling modes from controls located outside the MCR (operation of the RHR containment spray portion of Mode 74-03 from outside the MCR is not possible nor is it required). This mode contained two individual requirements.

Testing for this mode was fully satisfied by procedures 1-SR-3.3.3.2.1(74) and 1-SR-3.3.3.2.3(6) and consisted of verification, with the Emergency Transfer Switches in the NORMAL position, manual RHR operation of the LPCI, Torus cooling, and shutdown cooling modes from controls located outside the MCR was not possible; and verified that, with the Emergency Transfer Switches in the EMERGENCY position, manual RHR operation of the LPCI, Torus cooling, and shutdown cooling modes from controls located outside the MCR was possible 35and manual RHR operation from controls located inside the MCR was notpossible. No further testing of System 74 was required for Unit 1 recovery to verify this mode.*Mode 74-20, Provide a flow path and pressure boundary integrity for System 23,RHRSW, heat exchangers. This Mode contained one requirement. Testing for this mode was fully satisfied by procedures 1-SI-3.3.8.A and 1-SI-3.3.8.C, and consisted of verifying that pressure boundary integrity was maintained for the four Unit 1 RHR Heat Exchangers 1A, 1B, 1C, and 1D. No further testing of System 74 was required for Unit 1 recovery to verify this mode.*Mode 74-21, Provide a System 03, Reactor Feedwater, RPV low water level,Level 2, signal for a System 71, RCIC, initiation. This Mode contained one requirement. Testing for this mode was fully satisfied by procedures 1-SR-3.3.5.1.5(RWL A), 1-SR-3.3.5.1.5(RWL B), 1-SR-3.3.5.1.5(RWL C), 1-SR-3.3.5.1.5(RWL D), and 1-SR-3.3.5.2.4(FT), and consisted of verifying that the RCIC system received a Level 2 initiation signal from RHR logic relays 10A-K79A and 10A-K80A. No further testing of System 74 was required for Unit 1 recovery to verify this mode. *Mode 74-23, Provide an RHR isolation signal from System 64A, PCIS. Testrequirements for this mode was satisfied by other testing associated with System 74, RHR, BTRD, Mode 01 testing. No further testing of System 74 was required for Unit 1 recovery to verify this mode.*Mode 74-24, Provide for a divisional inhibit operation of the Unit 1 System 74,RHR Division II, and Unit 2 System 74, RHR Division I as part of the CommonAccident Signal (CAS) logic system. This mode contained two requirements.

Testing for this Mode was fully satisfied by procedures 1-SR-3.3.5.1.6(B I), and 1-SR-3.3.5.1.6(BII), and consisted of the following: Verified that the LOCA signal from System 74, RHR, of Unit 1, provided a divisional inhibit operation of the Unit 2 System 74, RHR Division I; and verified that the LOCA signal from System 74, RHR, of Unit 2, provided a divisional inhibit operation of the Unit 1 System 74, RHR Division II. No further testing of System 74 was required for Unit 1recovery to verify this mode. *Mode 74-25, Provide that a LOCA signal from Unit 1 System 74, RHR , and aLOCA signal from Unit 2 System 74, RHR, initiated a divisional inhibit operation as part of the CAS logic system. This Mode contained two requirements.

Testing for this mode was fully satisfied by procedures 1-SR-3.3.5.1.6(B I), and 1-SR-3.3.5.1.6(BII), which verified that the initiation of the Unit 1 and the Unit 2 accident signals are provided to the Emergency Core Cooling System (ECCS)preferred pump logic; and verified that the ECCS preferred pump logic system inhibited operation of Unit 1 System 74, RHR, Division II and Unit 2 System 74, RHR, Division I.

No further testing of System 74 was required for Unit 1 recovery to verify this mode.*Mode 74-26, Provide a Unit Priority Re-trip Signal to System 57-5, 4KV, fordiesel generator breakers as part of the CAS logic system. This Mode contained 36three requirements. Testing for this mode was fully satisfied by procedures 1-SR-3.3.5.1.6(A I), 1-SR-3.3.5.1.6(A II), 1-SR-3.3.5.1.6(B I), and 1-SR-3.3.5.1.6(BII), which verified that the all eight diesel generators auto-started on a CAS logic signal; verified that the unit priority re-trip initiated on a Unit 2 and Unit 3 concurrent LOCA signal; and verified that the unit priority re-trip initiated on a Unit 1 and Unit 3 concurrent LOCA signal. No further testing of System 74 was required for Unit 1 recovery to verify this mode.*Mode 74-27, Provide a LOCA signal from Unit 1 System 74, RHR , and Unit 2System 74, RHR, to System 57-5, 4KV, to inhibit the initiation of a Unit Priority Re-Trip signal. This Mode contained two requirements. Testing for this Mode was fully satisfied by procedures 1-SR-3.3.5.1.6(A I), 1-SR-3.3.5.1.6(A II), 1-SR-3.3.5.1.6(B I), and 1-SR-3.3.5.1.6(BII), and consisted of verification that the a unit priority re-trip block permissive signal is provided from Unit 1 to System 57-5, 4KV, by energizing relay 10A-K74A, in order to prevent a concurrent signal from Unit 2 tripping the diesel generator Division I loads; and Verified that the a unit priority re-trip block permissive signal is provided from Unit 2 to System 57-5, 4KV, by energizing relay 10A-K74B, in order to prevent a concurrent signal from Unit 1 tripping the diesel generator Division II loads. No further testing of System 74 was required for Unit 1 recovery to verify this Mode.

The inspectors reviewed the TSR and verified that, with the exception of Mode 74-01testing which was deferred as discussed above, the above RHR system modes were satisfactorily tested during the ongoing testing activities. For test requirements associated with Modes 74-04, 74-09, 74-10, 74-11, 74-14, 74-15, 74-16, 74-17, and 74-23 which were satisfied by other testing the inspectors concurred that no further testing of System 74 was required for Unit 1 recovery.CRD, TSR 1-BFN-BTRD-85The CRD system consisted of 15 BTRD Modes as follows:

• Mode 85-01, Provide for the following: A SCRAM signal from the RPS activatesthe CDR system to trip the SCRAM pilot valves, and to trip the Scram Discharge Volume (SDV) vent and drain pilot valves; due to the tripping of the pilot valves all control rods insert, and the SDV vent and drain valves close automatically; on a loss of power to the RPS all control rods insert, and the SDV vent and drain valves close automatically; the SCRAM insertion time for all control rod be within requirements; the stroke times for the SDV vent and drain valves be within requirements; adequate indication of the SDV vent and drains valves was in the Main Control Room (MCR); and the vent and drain valves open to drain the SDV only after a SCRAM reset. Testing for this Mode was performed by various Technical Instructions (TI), Surveillance Instructions (SR), and Post Modification Test Instructions (PMTI) including 1-TI-186, 1-SR-3.3.1.1.12, 1-SR-3.1.4.1,and PMTI-51080. Due to the current configuration of the system some of the testing did not meet the initial condition requirements such as control rods being at greater than 50% rod density, operation of the SDV valves at pressure, and reactor pressure vessel at 800 psig or greater. Consequently, PL items (PL-06-3698 and 3576) were issued to track the testing until initial conditions can be 37met. Further testing for Unit 1 recovery of System 85 for this Mode will betracked by the PL items.*Mode 85-02, Provide Primary Containment pressure boundary. Testrequirements for this Mode was satisfied by other testing associated with the System 64A, Primary Containment, BTRD. No further testing of System 85 was required for Unit 1 recovery to verify this Mode.*Mode 85-03, Provide Secondary Containment pressure boundary. Testrequirements for this Mode was satisfied by other testing associated with System 64C, Secondary Containment, BTRD. No further testing of System 85 was required for Unit 1 recovery to verify this Mode.*Mode 85-04, Provide Reactor Coolant pressure boundary. Test requirements forthis Mode was satisfied by other testing associated with System 68, Reactor Recirculation System, BTRD. No further testing of System 85 was required for Unit 1 recovery to verify this Mode.*Mode 85-05, Prevent rod withdrawal by verifying that rod block interlocks preventrod withdrawal by the Reactor Manual Control System (RMCS). Testing for this Mode consisted of two types of rod block interlocks, one from System 92, Neutron Monitoring and the other from System 79, Fuel Handling. Due to the condition of the Rod Block Monitor, System 92, and System 79 the testing was transferred to surveillance instructions. The first interlock was transferred to instruction 1-SR-3.3.2.1.1 and the second to 1-SR-3.9.1.1. Consequently, PL items PL-06-3658 and 3704 were issued to track the testing until test conditions can be met. Further testing for Unit 1 recovery of System 85 for this Mode will be tracked by the PL items.*Mode 85-06, Provide housing support to keep control rods in place. Testing forthis Mode was not required. This is a passive function and no physical action is required. The inspection of the housing support structure after reassembly was transferred to Surveillance Instruction 0-SI-4.3.B.2. No further testing of System 85 was required for Unit 1 recovery to verify this Mode. *Mode 85-07, Limit rod drop rate to less than 3.11 ft/sec Testing for this Modewas not required. The original design, as verified by developmental testing, was acceptable to ensure the function for this Mode. No further testing of System 85 was required for Unit 1 recovery to verify this Mode.*Mode 85-08, Provide rod position indication in the MCR. Testing for this Modeconsisted of for two requirements as follows: The first requirement was to verify position indication for each control rod to indicate latch position, travel from full in to full out, and over-travel position; and the second was to verify correct drive selected for movement and drive position. Testing for this Mode was performed and documented using technical instruction 0-TI-20. Due to the condition of some of the Rod Position Indicators a PL item was issued to track the testing until test conditions can be met. Further testing for Unit 1 recovery of System 85 for this Mode will be tracked by the PL item.

38*Mode 85-09, Provide SDV high water level signals for a total of three. Testingfor this Mode consisted of verifying for the West SDV and East SDV that a total of three high level signals are provided from each SDV as follows: The first and lowest level provided a high level alarm in the MCR for operator action; the second provided a rod block to prevent further withdrawal of any control rod; and the third provided a reactor SCRAM to System 99, RPS, from all four level switches, two per RPS trip system. Testing for this Mode was performed and documented by Surveillance Instruction 1-SR-3.3.1.1.13.

No further testing of System 85 was required for Unit 1 recovery to verify this Mode.*Mode 85-10, Provide SCRAM Discharge System low air header pressure signal.Testing for this Mode was not required. The function for this Mode, as stated in the SSA, was removed by DCN 51206. No further testing of System 85 was required for Unit 1 recovery to verify this Mode.*Mode 85-12, Provide system pressure boundary support to System 01, MainSteam, for greater than 30% turbine first stage pressure instrumentation.

Testing for this Mode was not required. The function for this Mode, as stated in the SSA, was removed by DCN 51206. The DCN deleted the Ros Sequence Control System, including the associated turbine first stage pressure switches, 1-PS-85-0061A and B, and pressure Transmitters 1-PT-0061A and B. No further testing of System 85 was required for Unit 1 recovery to verify this Mode.*Mode 85-13, Provide system pressure boundary in support of System 71, RCIC,for the automatic initiation mode and manual operation. Test requirements for this Mode was satisfied by other testing associated with System 69, Reactor Water Cleanup (RWCU), BTRD. DCN 51194 installed a check valve, 1-CHK-69-0629, in the RWCU. No further testing of System 85 was required for Unit 1 recovery to verify this Mode.*Mode 85-14, Provide Alternate Rod Insertion (ARI). Testing for this Modeconsisted of the following: Verified that an Anticipatory Transit Without Scram (ATWS) signal is generated on a System 03, Reactor Feed Water (RFW), low water level, Level 2, signal; verifyed that an ATWS signal is generated on a System 03, RFW, high reactor vessel pressure signal; verified that the ARI SCRAM valves open to vent upon an ATWS SCRAM signal; and verified that the ARI is confirmed by scram valve indicator illumination in the MCR on Panel 1-95-5, Full Core Display, and the indication was begun within 15 seconds of an ATWS SCRAM signal and was completed within 25 seconds. Testing for this Mode was performed and documented by two Surveillance Instructions and a WO as follows; 1-SR-3.3.1.1.12, 1-SR-3.3.4.2.4, and WO 06-724057-00. Due to the condition of the ATWS System a PL item, PL-06-3582, was issued to track the testing until test conditions can be met. Further testing for Unit 1 recovery of System 85 for this Mode will be tracked by the PL item.*Mode 85-15, Provide system pressure boundary to System 02, CondensateStorage, and Transfer, during HPCI open water suction supply mode from the Condensate Storage Tank. Test requirements for this Mode was satisfied by 39other testing associated with System 73, High Pressure Coolant Injection (HPCI),BTRD. This Mode is passive function and is the HPCI normal flow path. No further testing of System 85 was required for Unit 1 recovery to verify this Mode.*Mode 85-16, Provide selected rod identification to the Rod Block Monitor.Testing for this Mode consisted of verifying that the System 85, CRD, provided the selected rod identification to the Rod Block Monitor subsystem of System 92, Neutron Monitoring. Testing for this Mode was performed and documented by Surveillance Instruction 1-SR-3.3.2.1.1. Due to the condition of the Rod Block Monitor subsystem a PL item, PL-06-3658, was issued to track the testing until test conditions can be met. Further testing for Unit 1 recovery of System 85 for this Mode will be tracked by the PL item.The inspectors reviewed the TSR and verified that, with the exception of Mode 85-01,85-05, 85-08, 85-14, and 85-16 testing which was deferred as discussed above, the above CRD system modes were satisfactorily tested during the ongoing testing activities.

For test requirements associated with Modes 85-02, 85-03, 85-04, 85-13, and 85-15 which were satisfied by other testing the inspectors concurred that no further testing of System 85 was required for Unit 1 recovery. Additionally, the inspectors concurred that Modes 85-06, 85-07, 85-10, and 85-12 had not required any specific testing as discussed above. RPS, TSR 1-BFN-BTRD-99RPS consisted of seven BTRD Modes and testing requirements were satisfied byseparate testing from 42 surveillance instructions associated with System 01 Main Steam, System 03 Reactor Feed Water, System 47 Main Turbine Electro-Hydraulic Controls, System 64D Primary Containment Isolation, System 85 Control Rod Drive, and System 92 Neutron Monitoring. These 42 surveillance instructions performed overlap testing which included field inputs and outputs which either partially satisfied or fully satisfied the various RPS Modes. The Modes were tested as follows:*Mode 99-01, Provide automatic scram and Scram Discharge Volume (SDV) ventand drain valve isolation signal to the System 85, CRD. This Mode contained ten individual requirements. Eight of these requirements were partially satisfied and two were fully satisfied by PMTI 5108 and other applicable procedures. Testing for this Mode verified that System 85, CRD, received a HALF SCRAM signal from RPS channel A1 or A2 or B1 or B2. The following were partially satisfied:

Inboard and/or outboard MSIV's in selected pairs of steam lines are closed; low hydraulic fluid supply pressure to the turbine control valve fast acting disc dump valve; turbine stop valves in selected pairs of steam lines are closed; a signal indicating high pressure in the Reactor Pressure Vessel (RPV); a signal indicating low water level, Level 3, in the RPV; a signal indicating high drywellpressure; a signal indicating high reactor neutron flux; and a signal indicating ahigh SDV level. The following were fully satisfied: Manual reset of a SCRAM was inhibited for a minimum of 10 seconds following a SCRAM, and system response time is less than 50 milliseconds from the opening of the sensor contacts to the trip actuator SCRAM relay contacts. Due to the condition of the various systems that interface with the RPS Punch List (PL) items such as, PL-4006-3499 thru 3504, were issued to track the testing until testing conditions canbe met. Testing for this Mode will be satisfied by performing various system surveillance procedures such as the following: 1-SR-3.3.1.1.14(5I), (5II), (8I) and (8II); 1-SR-3.3.1.1.10(3A), (3B), (3C), and (3D); 1-SR-3.3.1.1.13(4A), (4B), (4C),

and (4D); 1-SR-3.3.1.1.13 (6A), (6B), (6C), and (6D); 1-SR-3.3.1.1.13; and 1-SR-3.3.1.1.16. These procedures are part of the various systems that interface with the RPS. Further testing for Unit 1 recovery of System 99 for this Mode will be tracked by the PL item. *Mode 99-02, Provide manual HALF or FULL SCRAM and SDV vent and drainvalve isolation signals to System 85, CRD. This Mode contained four individual requirements. Testing for this Mode was fully satisfied by procedure PMTI 51080 and consisted of verification that manually opening the RPS Motor Generator set output breakers initiated a Full Scram signal to System 85, CRD, from the RPS; that manually pressing either manual SCRAM switch initiated a HALF Scram signal to System 85, CRD, from the RPS; that manually pressing both manual SCRAM switches initiated a FULL SCRAM signal to System 85, CRD, from the RPS; and that placing the reactor mode switch in the SHUTDOWN position initiated a FULL SCRAM signal to System 85, CRD, from the RPS. Testing for this Mode was performed and documented by procedures PMTI-51080 and 1- SR-3.3.1.1.8(11). No further testing of System 99 was required for Unit 1 recovery to verify this Mode.*Mode 99-03, Provide a RUN Mode signal to System 64D, Primary ContainmentIsolation System (PCIS). This Mode contained one requirement. Testing for this Mode consisted of verifying that the RPS provided an MSIV closure permissive signal to the PCIS via the Reactor Mode Switch contacts when the switch was in the RUN position. Testing for this Mode was partially satisfied by procedure PMTI 51080. Due to the condition of the PCIS a PL item, PL-06-3504, was issued to track the testing until testing conditions can be met. Testing for this Mode will be satisfied by performing the following procedures: 1-SR-3.3.6.1.2 (ATU A), (ATU B), (ATU C), and (ATU D). These procedures are part of the System 64A, PCIS, BTRD, 1-BFN-BTRD-064A. Further testing for Unit 1 recovery of System 99 for this Mode will be tracked by the PL item.*Mode 99-04, Provide a Refueling interlock signal to the Reactor Manual Controlsubsystem of System 85, CRD. This Mode contained one requirement. Testing for this Mode consisted of verifying that the Reactor Mode Switch enabled the refuel interlock between the Reactor Manual Control subsystem and System 79, Fuel Handling when the mode switch is in the REFUEL position. Testing for this Mode was partially satisfied by procedure PMTI 51080. Due to the condition of the Rod Block Monitor a PL item, PL-06-3505, was issued to track the testing until testing conditions can be met. Testing for this Mode will be satisfied by performing procedure 1-SR-3.9.1.1. This procedure is part of the System 79, Fuel Handling, BTRD, 1-BFN-BTRD-079. Further testing for Unit 1 recovery of System 99 for this Mode will be tracked by the PL item.*Mode 99-05, Provide a trip signal to the breaker logic of the pump motors inSystem 68, Reactor Recirculation System, (RRS) to trip the motors. This Mode 41contained three individual requirements. Testing for this Mode was partiallysatisfied by procedure PMTI 51080 and consisted of the following: Verified a Turbine Control Valve fast closure trip, verified a Turbine Stop Valve closure trip, and verified that the Turbine Control Valve fast closure trip and Turbine Stop Valve closure trip were bypassed at < 30% reactor thermo power based on Main Turbine first stage pressure. Due to the condition of the turbine valves a PL item, PL-06-3506, was issued to track the testing until testing conditions can be met. Testing for this Mode will be satisfied by performing the following procedures: 1-SR-3.3.1.1.8(8); 1-SR-3.1.1.9(9); 1-SR-3.3.4.1.4; and 1-SR-3.3.1.1.15 (A1), (A2), (B1), and (B2). These procedures are part of the System 01, Main Steam, BTRD, 1-BFN-BTRD-01, and System 68, RRS, BTRD, 1-BFN-BTRD-068. Further testing for Unit 1 recovery of System 99 for this Mode will be tracked by the PL item.*Mode 99-06, Provide logic signals to System 64D, PCIS. This Mode containedtwo individual requirements. Testing for this Mode was partially satisfied by procedure PMTI 51080 and consisted of the following: Verified a reactor pressure vessel water level low, Level 3, signal as sensed by the associated analog trip unit; and verified a drywell high pressure signal as sensed by the associated analog trip unit. Due to the condition of the PCIS and System 03, Main Feedwater, PL items, PL-06-3501 and 3504, were issued to track the testing until testing conditions can be met. Testing for this Mode will be satisfied by performing the following procedures: 1-SR-3.3.1.1.13 (4A), (4B), (4C), and (4D); and 1-SR-3.3.1.1.13 (6A), (6B), (6C), and (6D). These procedures are part of the System 03, Main Feedwater, BTRD, 1-BFN-BTRD-03, and System 64, PCIS, BTRD, 1-BFN-BTRD-064. Further testing for Unit 1 recovery of System 99 for this Mode will be tracked by the PL item. *Mode 572-03, Provide 120V AC power to System 99, RPS, and the ability tode-energize the RPS from outside the Main Control Room (MCR). This Mode contained one requirement. Testing for this Mode was fully satisfied by procedure PMTI 51080. The testing consisted of verifying that the RPS can be de-energized from outside the MCR, from Battery Board 1, Panel 9, RPS panel distribution breakers 903 and 953. No further testing of System 99 was required for Unit 1 recovery to verify this Mode.The inspectors reviewed the TSR and verified that, with the exception of Mode 99-01,99-03, 99-04, 99-05, and 99-06 testing which was deferred as discussed above, the above RPS system modes were satisfactorily tested during the ongoing testing activities.

b.3Inadequate RHR Logic Test InstructionThe inspectors reviewed the circumstances associated with an event which hadoccurred on December 3, 2006, where an inadequate Unit 1 restart test instruction had resulted in an unplanned LCO entry due to a Core Spray/RHR Loop I Auto Initiation Lockout on Unit 2. During performance of Surveillance Instruction, 1-SR-3.5.1.9, Simulated Auto Actuation of Loop I RHR Pumps, the licensee received an unintended lockout of the Unit 2 Loop I RHR Pumps (2A and 2C) and Core Spray Pumps (2A and 422C). This surveillance satisfies TS 3.5.1.9 for the Unit 1 Loop I RHR Logic. Thecondition was immediately recognized by the control room operators and testing stopped. The license entered TS LCO 3.5.1 Conditions A and H, requiring immediate entry into TS 3.0.3. The Unit 2 ECCS pumps were inoperable for approximately four minutes, the initiation signal reset and the licensee exited the LCO. This problem was documented by the licensee under PERs 115833 and 115837. The inspectors reviewed these PERs and noted that the event was attributed to aninadequate test instruction. The licensee determined that the LPCI AUTO-INIT Inhibit (SYS I) Handswitch, 1-HS-074-0153, on Panel 1-9-32 being caution tagged in the INHIBIT position prior to performance of testing prevent inadvertent Unit 2 relay actuation during ongoing Unit 1 testing. However, surveillance instruction 1-SR-3.5.1.9 did not address checking the position of this handswitch. Additionally, insulating boots were needed on relay, 1-RLY-074-10A-K73A, contacts 5-6 and 7-8 in Panel 9-32 during performance of the testing to prevent an undesired lockout on the Unit 2 Loop I ECCS pumps. The inspectors verified that surveillance instruction 1-SR-3.5.1.9 was revised to correctly address the position of the Inhibit handswitch and install the required insulating boots to prevent a lockout on the Unit 2 Loop I ECCS pumps. The inspectors also noted that the corresponding logic inhibit handswitch for the Unit 1 Core Spray logic had already been addressed by 1-SR-3.5.1.6(CS I) which also satisfies TS 3.5.1.9 for the Core Spray Logic. Additionally, the inspectors verified that the affected Unit 2 procedures, 2--SR-3.5.1.9 (RHRI) and 2-SR-3.5.1.9 (RHRII) were to be revised by separate action required by PER 115837. These Unit 2 procedures were on hold and required revision prior to use. Inspectors identified a violation of 10 CFR 50, Appendix B, Criterion V, associated withthe testing of Unit 1 ECCS Logic. 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings requires in part that, "activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings." Specifically on December 3, 2006, licensee used an inadequate Unit 1 restart test instruction which resulted in an unplanned LCO entry due to a Core Spray/RHR Loop I Auto Initiation Lockout on Unit 2. Contrary to 10 CFR 50, Appendix B, Criterion V, the procedure did not adequately specify measures to prevent a lockout of the Unit 2 Loop I ECCS pumps . The licensee documented this deficiency in PERs 115833 and 115837. This violation is being treated as a Severity Level IV NCV consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000259/2006-09-01, "Inadequate Instructions for Testing ECCS Logic" .

c. Conclusions

Implementation of restart testing activities was generally acceptable. However, licenseetest procedures had not adequately specified measures to prevent a lockout of the Unit 2 Loop I ECCS pumps resulting in a NCV. Minor test deficiencies which did not affect the results of the testing, were identified during performance of testing. Licensee processes were effective at identifying problems before components were placed in service 43E1.5Special Program Activities - Cable Installation and Cable Separation (37550, 37551)

a. Inspection Scope

This inspection focused on the corrective actions that were being implemented byTennessee Valley Authority (TVA) to resolve the cable separations concerns for Unit 1 Recovery. This inspection included a review of issues addressed in calculations EDQ-0999-910078 for external separation and EDQ-19992003061 for internal separation issues. The inspection was conducted by reviewing work order records, design basis documents, corrective actions, exceptions, drawings, and conducting walkdown inspections of methods used for achieving divisional separation or functional redundancy for Unit 1. b.ObservationsThe inspector reviewed the licensee's corrective actions and extent of condition (EOC)for the previous examples of cable separation violations. Those corrective actions were found to be adequate, the reestablishment of the 95/95 confidence level was conservative, and the extent of condition was prescriptive. The inspector reviewed examples of punch list walkdowns, Design Change Authorizations (DCAs), and Post Issuance Changes (PICs) used to modify DCNs. The inspector performed an independent review of closed stages that had been walked down by staff for return to operations (RTO).

b.1Internal Separation:The inspector reviewed criteria for spacial separation, connection details, and otherconstruction requirements to verify that as-built configurations were consistent with standards and requirements for wires and separation for cable routing inside panels.

The DCAs selected for the review were: 51080-124, 51094-715, and 51105-029. The inspector performed independent review of punch list packages of closed stages that had been walked down by staff for RTO. The inspector verified that field installations met divisional separation or functional redundancy separation. The inspector found that conduits 1ES239-II and 1ES5801-II were incorrectly tagged as 1ES239-I and 1ES5801-I. The licensee generated PER 115700 to document this issue.

b.2External Separation:The first week (November 27 - December 1, 2006) of the inspection consisted of areview of design criteria documents (DCD) and walkdowns of areas in the cable vault and tunnel focusing on external cable separations. The inspector reviewed criteria for spacial separation, connection details, and other construction requirements to verify that as-built configurations were consistent with standards and requirements for cables, cable routes, cable trays. The inspector verified that field installations met divisional separation or functional redundancy separation and maintains single failure criteria in accordance with design criteria. The first week of the inspection consisted of review of walkdowns of areas in the control room and the cable vault and tunnel focusing on 44external cable separations. The cables selected are listed in Table A.1 in theattachment. The inspector identified one violation of NRC requirements as discussed in SectionE1.5.b.2.1. As a result of this violation, TVA generated PER 115699 and corrective actions. The corrective actions became part of the scope for the second week (January 8-12, 2007) of the inspection which also consisted of increasing the scope for an additional population of 17 cables located in the Main Control Room, Dry Well Area, Reactor Building, Cable Spread Room and Auxiliary Instrument Room. The cables selected are listed in Table A.2 in the attachment and were reviewed to verify that installation activities were in accordance with BFN-50-728, Physical Independence of Electrical Systems, Rev.16. The inspector reviewed criteria for spacial separation to verify that as-built configurations were consistent with standards and requirements for cables, cable routes, and cable trays. The inspector verified the use of cable tray covers and performed walk-downs of existing trays and new cable trays. In addition, the inspector reviewed criteria used to calculate cable tray loading and performed walk downs of cable trays to verify that installed cables were within the limits of cable tray fill located in the control room and in the cable spreading room.

b.2.1Violation of Separation Requirements in Cable Spreading Room:The inspectors identified a violation of 10 CFR 50 Appendix B, Criterion III, DesignControl, for three cables located in the CSR. The inspector found that the installed Division I conduit 1ES832-I consisting of control cables 1PC334-I, 1PC349-I, and 1ES831-I were routed within Division II cable tray MK-ESII instead of LW-ESI as depicted in 45W808, Layout Drawing, Sh.10, Rev. 27. The inspector found that the as-found configuration was not in accordance with licensee separation requirements, as specified in BFN-50-728, Section 3.6.1. This section states, in part, electrical wiring for the safety systems shall be segregated into separate divisions such that no single event, such as short circuit, fire, pipe rupture, or missile is capable of disabling sufficient equipment to prevent the required safety function. Contrary to this requirement, during the walkdown inspections of the cable trays, it was discovered that the cables from conduit 1ES832-I did not meet separation requirements. Cable 1PC334-I is classifiedas safety-related. Its function is opening/closing Group 6 Primary Containment Isolation System (PCIS) valves. Loss of power results in the valve repositioning to its fail safe position (closed). Cable 1PC349-I is not classified as safety-related. Its function is opening/closing 1-FCV-43-13, Recirculation Loop Inboard Sample valve. Loss of power results in the valve repositioning to its fail safe position (closed). Cable 1ES831-I is not classified as safety-related. Its function is to control opening/closing 1-FCV-75-57, Inboard Drain valve and is part of the Core Spray (CS) system. Loss of power results in the valve repositioning to its fail safe position (closed). PER 115699 was generated to document this finding. TVA provided a response detailing a planned course of activities safety equipment/significance evaluation, EOC, corrective actions for nonconformance, and an evaluation that reestablished the basis of the 95/95 confidence analysis to resolve issues in the CSR. 10 CFR 50, Appendix B, Criterion III, Design Control, requires that measures beestablished to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Contrary 45to the above, on Nov. 30, 2006, measures were not adequate to assure that divisionalseparation for cable from opposite divisions were maintained. As a result of these inadequate measures, Division I cables exiting conduit 1ES832-I, were routed in Division II cable tray without the divisional separation being met. This violation wascharacterized at Severity Level IV in accordance with the guidance contained in the NRC Enforcement Policy, Supplement II, Facility Construction. In addition, this violationis being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy, NCV 50-259/2006-09-02, Measures Were Not Adequate to Assure that Cables from Opposite Divisions Were Separated.

b.2.2Violation of Separation Requirements in Auxiliary Instrument Room:The inspectors identified a violation of 10 CFR 50 Appendix B, Criterion III, DesignControl, located above panel 1-PNLA-009-0042, bay 1, in the Auxiliary Instrument Room. The installed conduit, labeled 1ES5659-II consisting of High Pressure Coolant Injection (HPCI) system Division I cables (1ES181-IS2 and 1ES190-IS2), was incorrectly labeled and routed within a region of Division I enclosed raceway called the "top hat" without the required HPCI and Automatic Depressurization System (ADS) independence being maintained. The inspector found that redundant ADS cables (1ES15-IS1 and 1ES16-IS1) feed circuits for the Residual Heat Removal (RHR) system and CS system logic. All four cables were routed within the "top hat" region located above panel 1-PNLA-009-0042 Bay 1.Maintaining HPCI and ADS independence requires assuring that there is no credibleDivision I cable failure which could disable ADS and simultaneously initiate HPCIIsolation. HPCI is a Division II system with the exception of its inboard isolation valve and logic which is Division I. Therefore, HPCI isolation logic can be initiated by either Division I or Division II components. ADS is a Division I system but uses both Division I and Division II components to establish redundant initiation logic. The logic circuitry using Division II instrumentation depends upon Division I power. The HPCI Division I cables 1ES181-IS2 and 1ES190-IS2, feed circuits that are inputs to HPCI Logic Bus A.

HPCI logic Bus A relies upon Division I power, instrumentation, relays and cables. The ADS Division I cables, 1ES15-IS1 and 1ES16-IS1, feed circuits that are inputs to logic Bus B (RHR and CS systems). ADS logic Bus B relies upon Division II power, instrumentation, relays and cables, but also uses Division I power sources and cabling.

A Division I cable failure which involves required ADS Division I cables will also initiate aHPCI isolation condition. The licensee issued PER 117921 to document this nonconformance.10 CFR 50, Appendix B, Criterion III, Design Control, requires that measures beestablished to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. These measures shall include provisions to assure that appropriate quality standards are specified and included in design document and that deviations from such standards are controlled. FSAR Section 8.9.4 states that "No single control panel, local panel, orinstrument rack includes wiring essential to the protective function of both redundant systems, which are backups for each other (Division I and Division II)..." TVA GeneralDCD BFN-50-728, Rev.16, was issued Aug 3, 1987 as a product of the U2 restart activities under the Design Baseline and Verification Program which was reviewed and 46accepted by the NRC in NUREG-1232. BFN-50-728 states that installation activities will"as a minimum requirement, satisfy the single failure criteria" as described in IEEE 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations," which states in part concerning the application of the single failure criteria, "complete isolation and/or separation of the components of the redundant system shall be provided." BFN-50-728 also references documents that address special separation of circuits specific to HPCI and ADS. Quality Information Request/Release (QIR) NEB-84004, "Criteria for Special Cable Separation," states as a requirement "The ADS and HPCI Division Icables and intra-panel wiring shall be separated to ensure no single failure can disable both systems." Calculation ED-Q0001-920589, Division I Cables Requiring Separation to Maintain "HPCI-ADS Independence plus Significant ADS Modifications, Rev. 12, section HPCI-ADS Independence Requirements" states that HPCI and ADS independence requires assuring that there is no credible Division I cable failure which could disable ADS and simultaneously initiate HPCI isolation. Contrary to the above, these requirements were not met as of January 12, 2007, in that activities implemented for isolation of redundant divisions HPCI and ADS in the "top hat" region of 1-PNLA-009-0042, located in the Unit 1 Auxiliary Instrument Room, were not adequate to ensure that divisional independence for cables from opposite divisions were maintained. This violation is a second example of the NCV previously discussed in Section E1.5.b.2.1 above.

b.2.3Potential Violation of Separation Requirements in Auxiliary Instrument Room:The inspector identified a configuration control issue in the Auxiliary Instrument Room. During the walkdown inspections of enclosures, it was discovered that divisional and non divisional cables share common raceways called "top hats, located above the instrument panels" These top hats do not appear to be adequately analyzed for raceway separation in accordance with BFN-50-728. As a result of this, divisional cables may be routed in common raceways without divisional separation being met.An enclosure, as defined in BFN-50-728, is an identifiable housing such as a cubicle,compartment, sub-compartment, panel, sub-panel, terminal box, or enclosed raceway, used for electrical equipment or cables. Raceway, as defined in BFN-50-728, is "any channel that is designed and used expressly for supporting wires, cables, or busbars.

Raceways consist primarily of, but are not restricted to, cable trays and conduits." The area termed "top hat," above panels in the Auxiliary Instrument Room, is not defined in BFN-50-728. The area is an enclosed raceway that houses cables. It is separate from the panels, but sits directly on top of the panels. The area is closed on three sides with a removable face plate on the front. Cables can pass through the "top hat" by penetrations or openings on the top and bottom. There are no barriers inside of the enclosure. Divisional and non-divisional cables are routed within the enclosure. The licensee could not determine whether cables inside of the "top hat" were adequately separated to meet the requirements for divisional separation or functional redundancy as defined in BFN-50-728. In prior discussions, TVA indicated to NRC staff that the area is not clearly identified asmeeting "external" separations criteria, and that requirements for the "top hat" are addressed in the external separations portion BFN-50-728. The licensee maintained, at that time, that compliance was met for the top hat region by imposing the same 47separation criteria as defined for the cable trays. Consistent with this position, during aninspection conducted between January 8-12, 2007, the licensee maintained that the "top hat" was regarded as raceway, and therefore met external separation requirements.

This position could not be supported by any requirements or the DCD's. Subsequently, the licensee conducted additional reviews and concluded that the area is internal to the panel and should thereby be considered intra-panel thereby meeting requirements for internal separation as defined in BFN-50-728. The requirements for the "top hat" region could not be determined during the inspection. The licensee did not present evidence that supported the position whether the "top hat" should meet internal or external separation requirements. This issue will be tracked as URI 05000259/2006-009-03, Criteria Was Not Adequately Defined to Ensure Divisional Separation for Cables Were Maintained.

c. Conclusions

Two examples of a Severity Level IV NCV were identified for failure to comply with 10CFR 50, Appendix B, Criterion III, in that, measures were not adequate to assure thatcables for ADS and HPCI above Panel 1-9-42 Bay 1 were separated and measures were not adequate to assure that cables from opposite divisions in the Cable Spreading Room were separated. This resulted in multiple configurations of safety systems in the plant deviating from DCD requirements. Based on the above violation, additional inspections will be required to determine if the Electrical Cable Installation and Separation Special Program is being implemented satisfactorily.Corrective ActionsThe inspector identified examples in which the corrective action program has not beeneffective at identification and resolution of issues related to cable separation issues.

During the first week of the inspection, the licensee generated the following PERs as a result of the inspection: 115696, 115697, 115699, 115700, 115701, and 117202. PER 115699 is documented in this report as the first example of NCV 05000259/2006-09-02.

During the second week of the inspection the inspector reviewed the corrective actions performed by TVA as a result of PER 115699. The review focused on TVA's actions which included a walkdown of all divisional cables that transition from conduit to cable tray in the Unit 1 cable spreading room. The licensee performed a random sample walkdown of divisional cables that transition from Unit 1 control room panels to cable trays in the Unit 1 cable spreading room. TVA performed a walkdown of conduit 1ES832-I to confirm that installation was in accordance with design output documents and a walkdown of the redundant components cables that were identified in PER 115699. The licensee also reviewed the internal panel routing of cables in conduit 1ES832-I and the redundant division II cables. During the course of both inspection weeks, the inspector reviewed the resolutions related to PERs: 113566, 107116, 107138, 107488, 113286, 113926, 113374, and 113566. As a result of the second week of inspection, the licensee generated the following PERs: 117831, and 117921.

48E1.6Special Program Activities - Cable Ampacity (37550)

a. Inspection Scope

The inspectors reviewed three design change notices (DCNs), that the licenseeprepared and implemented for correcting cable ampacity problems involving "V5" medium voltage power cables used as power feeders at a system nominal voltage of 4160 VAC. The scope of the review included an evaluation of the cable ampacity calculations in addition to procurement documents prepared for purchase of the replacement cables to identify the cable type, and to verify that appropriate technical and quality requirements had been specified for the replacement cables. The inspectors also reviewed cable route information delineated on cable report data sheets, (i.e., cable pull slips), and performed a field inspection of selected cables to verify that the cables were installed in accordance with requirements specified in the DCN packages.

b. Findings and Observations

The inspectors reviewed DCN 51222 that was prepared for correcting cable ampacityproblems involving V5 power cables used as power feeder cables for Residual Heat Removal (RHR) pumps 1A, 1B, 1C, and 1D. The cables involved were ES125-I for RHR pump 1A; ES2625-II for RHR pump 1B; ES173-I for RHR pump 1C; and ES2673-II for RHR pump 1D. The RHR pump motors power feeder cables consisted of three single conductor 500 MCM and/or 400 MCM cables installed in conduits and/or cable trays.

The inspectors reviewed the procurement documents for the cables to identify the cable type, and verify that 10 CFR 50.49 environmental qualification requirements were satisfied when specified in the DCN. Material issue tickets prepared for the installed cables were evaluated by the inspectors to identify the cable reels from which the installed cables were obtained. The inspectors also verified that the cable reels were the ones identified in the procurement documents that purchased the installed cables and that the cable types, and other technical and quality requirements specified in the procurement documents were correct for the installed cables. Additionally, cable route information delineated on cable pull slips was evaluated by the inspectors to identify the as-installed cable routes, and to verify the accuracy of the information that was used as design inputs to the cable ampacity calculations. The inspectors reviewed the RHR motor nameplate data to verify the motor full load current and its use as a design input to the cable ampacity calculation. The inspectors evaluated the cable ampacity calculation and verified that the power feeder cables had positive cable ampacity margin based on the requirements of Electrical Design Standard DS-E12.63, and the as-installed cable routes. The inspectors performed field inspections of the as-installed cable routes for RHR pump 1A and 1C motor feeders and verified that the cables were installed in accordance with the requirements shown on approved cable tray and conduit layout drawings, and verified the cable ampacity calculation design input information. The inspectors also reviewed DCN 51223 that was prepared for correcting cableampacity problems associated with the Core Spray (CS) pump motors power feeder cables. The cables involved were 1ES5404-I for CS pump 1A; 1ES5412-II for CS pump 1B; 1ES5408-I for CS pump 1C; and 1ES5416-II for CS pump 1D. The CS pump motors power feeder cables consisted of 3 single conductor #2/0 cables installed in conduits and/or cable trays. The inspectors reviewed the procurement documents for 49the cables to identify the cable type and verify that 10 CFR 50.49 environmentalqualification requirements were satisfied when specified in the DCN. Material issue tickets prepared for the installed cables were evaluated by the inspectors to identify the cable reels from which the installed cables were obtained. The inspectors also verified that the cable reels were the ones identified in the procurement documents that purchased the installed cables; and that the cable types, and other technical and quality requirements specified in the procurement documents were correct for the installed cables. Additionally, cable route information delineated on cable pull slips was evaluated by the inspectors to identify the as-installed cable routes, and verify the accuracy of the information that was used as design inputs to the cable ampacity calculations. The inspectors reviewed the CS motor nameplate data to verify the motor full load current and its use as a design input to the cable ampacity calculation. The inspectors evaluated the cable ampacity calculation and verified that the power feeder cables had positive cable ampacity margin based on the requirements of Electrical Design Standard DS-E12.63, and the as-installed cable routes. The inspectors performed field inspections of the as-installed cable routes for CS pump 1A and 1C motor feeders, and verified that the cables were installed in accordance with the requirements shown on approved cable tray and conduit layout drawings, and accurately reflected design input information to the cable ampacity calculation.

Additionally, the inspectors reviewed DCN 51216 that was prepared for installation of new dry type transformers for 480 V Shutdown Board 1A and 1B normal supply transformers TS1A and TS1B respectively. The replacement transformers had ratings of 1000/1333 KVA, AA / FA ratings to provide additional capacity to the 480 V distribution system. The inspectors reviewed and evaluated the replacement of the transformers primary feeder cables based on the increase in transformer KVA ratings.

The cables involved were 1PP9857-IA for 480 VAC Shutdown Board 1A, and 1PP9859-IIC for 480 VAC Shutdown Boards 1B.

The transformer primary feeder cables consisted of three single conductor # 4/0 cables installed in conduits. The inspectors reviewed the procurement documents for the cables to identify the cable type and verify that 10 CFR 50.49 environmental qualification requirements were specified. Material issue tickets prepared for the installed cables were evaluated by the inspectors to identify the cable reels from which the installed cables were obtained. The inspector also verified that the cable reels were the ones identified in the procurement documents that purchased the installed cables and that the cable types, and other technical and quality requirements specified in the procurement documents were correct for the installed cables. Additionally, cable route information delineated on cable pull slips was evaluated by the inspectors to identify the as-installed cable routes, and verify the accuracy of the information that was used as design inputs to the cable ampacity calculations.The inspectors reviewed the name plate data for transformer 1B and verified that thetransformer primary full load current for both the "AA" and "FA" ratings was bounded by the results of the cable ampacity calculation, and that the transformer primary power feeder cables had positive ampacity margin based on the requirements of Electrical Design Standard DS-E12.63 and the as-installed cable routes. The inspectors also reviewed a small sample of V3 cables, ( 250 VDC / 240 VDC controlcables having less than 10 amperes full load current) that were reclassified as V4 or low 50voltage power cables. The cables reviewed were 1ES1400-I, 1ES1557-I and 1PC381-II. The inspectors reviewed the cable ampacity calculation of record for the above low voltage power supply cables to verify that the cables had positive cable ampacity margin based on the requirements of DS-E12.6.3 and the as-installed cable routes.

c. Conclusions

The inspector concluded that the DCNs implemented to correct cable ampacityproblems involving power feeder cables for the RHR and CS pump motors were technically adequate, and provided positive margin for the power feeder cables ampacity. Additionally, the plant modifications which replaced transformer primary feeder cables for transformers TS1A and TS1B feeding 480 V Shutdown Boards 1A and 1B respectively, demonstrated that positive margin had been established for the transformer primary power feeder cables ampacity. The ampacity calculations completed for the cables inspected demonstrated that the cables were correctly sized in accordance with TVA's Design Standard DS-E12.6.3 and that the installed cables are capable of supporting the re-start of Unit 1. Based on the results of this inspection, no additional inspection of this special program is planned.E1.7Special Programs Activities - Environmental Qualification (EQ) of Electrical Equipmentand Piece Parts Qualification (51053)

a. Inspection Scope

The NRC had previously reviewed and accepted the Browns Ferry environmentalqualification (EQ) special program that was implemented to support restart of Units 2 and 3. The evaluation of the EQ special program is discussed in Section 3.2 of NUREG-1232, Volume 3, dated April 1989. In that report, the NRC concluded that the Browns Ferry special program for EQ of electrical equipment located in harsh environments was in compliance with the requirements of 10 CFR 50.49,

"Environmental qualification of electric equipment important to safety for nuclear power plants." The piece part qualification program is evaluated and accepted in NUREG-1232, Volume 3, Supplement 2. The primary focus of the piece parts special program was to ensure that equipment previously qualified had not been degraded through the use of unqualified spare and replacement parts.This inspection examined both the EQ and Piece Parts Special Programs that werebeing implemented to support Browns Ferry Unit 1 restart.

The components and documents reviewed are listed in the Attachment to the report.

b. Observations and Findings

The inspectors compared the Unit 1 EQ Program to the Units 2 and 3 programs todetermine if they were equivalent. The inspectors found that the Unit 1 EQ Program uses the same processes and procedures that were used for the Units 2 and 3 EQ Programs. The existing Units 2 and 3 Equipment Qualification Data Packages (EQDPs)including the Qualification Maintenance Data Sheets (QMDS) were being revised to incorporate the Unit 1 EQ equipment. In addition, a small number of new EQDPs were 51being developed to address some replacement EQ equipment items that will only beinstalled in Unit 1. The inspectors noted that the licensee had issued design changes to replace most ofthe Unit 1 EQ equipment including cables and splices prior to Unit 1 restart.

The number of saved EQ components, cables, and splices were:*377 of 1763 cables

• 18 of 571 splices, and *27 of 1541 components other than cables and splicesThe licensee's process requires that the saved components be added to the EQProgram prior to Unit 1 restart.The licensee's piece parts qualification special program required that the maintenancerecords for the 27 saved components be reviewed to verify that the EQ qualification had not been invalidated or degraded by the use of unqualified piece parts or sub-components during maintenance activities. The licensee had completed reviews for 23 of the 27 saved items. The licensee found that one of the items had been degraded when a non-EQ qualified coil was installed during maintenance. This was not a violation of the EQ program due to the fact that the equipment was located in a mild environment with Unit 1 not operating and de-fueled. WO 05-711005-000 has been initiated to replace the coil with an EQ qualified coil. The four remaining items to be evaluated are scheduled to be completed prior to Unit 1 restart. The inspectors reviewed the completed evaluations for the 23 saved items to confirm that these components were acceptable for EQ applications. The components reviewed are listed in the Attachment.

The inspectors performed field walk down inspections of a selected sample of EQ components consisting of motor operated valves, transmitters, flow switches, temperature elements, limit switches, solenoid valves, and electrical penetrations. The components were inspected to verify that they were installed in accordance with the EQ requirements discussed in the associated Qualification Maintenance Data Sheets. The components were also examined to verify that they were not degraded or damaged during installation. However, if damage was noted, the inspectors verified that the problem had previously been identified and documented by the licensee and included in the corrective action program. The inspectors examined the motor operated valve component installations to verify thatcomponents were properly mounted and oriented; housing and motor drains (T-drains)were in place and in good condition; grease reliefs were installed and unobstructed; and housing covers were in place. The transmitters, solenoid valves, pressure switches, limit switches, and temperature elements were inspected to verify that they were properly mounted; that conduit seals were installed if required; and that covers were in place and in good condition. One particular model of Rosemount transmitters had spare conduit ports which had to be sealed with a stainless steel plug. The inspectors verified that the spare conduit shipping caps had been removed and replaced with a stainless steel plug in accordance with the QMDS requirements or a work order was open to 52install the plug. The in-board and out-board sides of the electrical penetrations for thedrywell were inspected for signs of damage to the pigtail cables and splices. The inspectors reviewed design drawings, Qualification Maintenance Data Sheets,vendor manuals, work order records, and PERS to confirm that components were being installed in accordance with the EQ program. The following findings were identified: T-Drain on Limitorque Operator Has Been Plugged with PaintA non-cited violation of 10 CFR 50, Appendix B, Criterion XVI was identified for failing torecognize that the motor T-drain on valve actuator 1-MVOP-075-009 had been plugged with paint. As a consequence, the environmental qualification of the valve actuator had been degraded.During a walk down inspection of Residual Heat Removal (RHR) valve actuator 1-MVOP-075-0009, the inspectors observed that the motor housing T-drain had been plugged with paint. The valve actuator had been repainted as part of the restart activities for Unit 1. The inspectors found that the licensee was not aware of this problem. In addition, the valve actuator had been EQ baselined for SPOC II without this problem being identified. This issue is more than minor because the T-drain is required by the QualificationMaintenance Data Sheet MOV-002, "AC Actuators - (Outside Drywell) Limitorque" to maintain the environmental qualification of the actuator. The T-drain had been made inoperable when it was plugged with paint, thus degrading the qualification of the actuator. The fact that the motor T-drain was plugged with paint is a condition adverse to quality. 10 CFR 50 Appendix B, Criterion XVI, "Corrective Action," requires that conditions adverse to quality be promptly identified and corrected.Contrary to the above, at the time of this inspection on October 18, 2006, the motor T-drain on RHR valve actuator 1-MVOP-075-0009 was plugged with paint, a condition adverse to quality, and the licensee had not promptly identified and corrected the problem. As a consequence, the environmental qualification of the actuator had been degraded. A Severity Level IV Non-cited Violation (NCV) 50-259/2006-09-04, T-Drain On Limitorque Operator Has Been Plugged With Paint, was identified. This violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy.

This issue was documented by the licensee in PER 113105. Transmitter Cover O-Ring Not ReplacedA non-cited violation of 10 CFR 50, Appendix B, Criterion V was identified because thehousing covers on flow transmitter 1-FT-23-0036 were removed, re-installed, and torqued without replacing the O-rings in accordance with the QMDS instructions. This resulted in the EQ of the transmitter being degraded. QMDS No. XMTR-001, "Pressure Transmitter - Rosemount Model 1153B," has amaintenance requirement to replace the O-rings each time the housing covers are 53removed. The inspectors reviewed the WO 02-015487-033 which installed the coverson flow transmitter 1-FT-23-00036 and found that new O-rings had not been installed prior to replacing and torquing the covers. The WO was reviewed and closed without this deficiency being identified. It appears that the covers were removed and the old O-rings were reused. This does not comply with the instructions in QMDS No. XMTR-001 which specifies that the O-rings must be replaced after the cover is removed. The licensee had identified in PER 111816 the lack of a formal process on Unit 1 to establish a QMDS baseline replacement of all O-rings and gaskets for all EQ instruments, and associated cover torquing. The inspectors reviewed this PER and did not consider the failure to follow QMDS requirements as the same problem described in the PER, so the licensee was not given credit for identifying this finding.This issue is more than minor because it had the potential to degrade the qualification ofthe transmitter. 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requiresthat activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. QMDS No. XMTR-001, "Pressure Transmitter - Rosemount Model 1153B," has a maintenance requirement to replace the O-rings each time the housing covers are removed.Contrary to the above, on August 18, 2005, the QMDS instructions were not followed, inthat, both electronic housing covers on flow transmitter 1-FT-023-00036 were removed and re-installed by WO 02-015487-033 without replacing the O-rings. This resulted in the EQ of the transmitter being degraded. A Severity Level IV NCV 50-259/2006-09-05, Transmitter Cover O-Ring Not Replaced As Required By QMDS, was identified. This violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy. This issue was documented by the licensee in PER 113169. Corrective Actions Associated with PER 113105The inspectors subsequently reviewed licensee actions associated with PER 113105,categorized as a Level C PER. The licensee's extent of condition review and two corrective action items associated with this PER were reviewed by the inspectors. The licensee's extent of condition included a total of 67 MOV's in various systems including System 01, Main Steam System (MS); System 23, Residual Heat Removal Service Water (RHRSW); System 73, High Pressure Coolant Injection (HPCI); and System 75, Residual Heat Removal (RHR).Corrective Action 113105-01 required that WOs be issued to perform inspections ofthese MOV's including the limit switch compartment T-drains, and to remove any drain obstructions found. WOs included 06-724635-00 for System 01; WO 06-724637-00 for System 23; WO 06-724646-00 for System 73; and WO 06-724648-00 for System 75.

The inspectors reviewed these WOs and did not identify any problems with the licensee's corrective actions. Additionally the inspectors noted that Corrective Action 113105-02 required that a training brief be held with all painters. The briefing included pictures of a T-drain in the proper unpainted condition and stated that if a painter had any questions they were to contact their supervisor.

54Corrective Actions Associated with PER 113169The inspectors subsequently reviewed licensee actions associated with PER 113169,categorized as a Level C.

The licensee's cause determination and corrective actions associated with this PER were reviewed by the inspectors.The inspectors determined that replacement flow transmitter, 1-FT-23-0036, RosemountModel 1153B, was originally shipped from the vendor, with qualified O-rings, and arrived onsite with the covers installed hand tight, the transmitter was checked out of the power stores, the technicians removed the covers, bench calibrated the transmitter, then replaced the covers hand tight, and returned the transmitter to power stores. The transmitter was subsequently checked out of the power stores, physically installed on the applicable instrument rack, the transmitter was connected both electrically and mechanically, the calibration was verified, and the covers were torqued tight using WO 02-015487-33. The licensee determined that the procedure had not fully addressed the initial installation of Rosemount transmitters. The licensee's immediate corrective actions required that until the covers were correctly torqued the O rings had not been under compression and consequently were not replaced. The problem was subsequently addressed by WO 06-7242330-00 which replaced the O-rings and properly torqued the housing covers on the flow transmitter.

c. Conclusions

The inspectors concluded that the Special Programs for EQ of Electrical Equipment andComponent/Piece Parts qualification were adequate to support Unit 1 restart. The EQ special program will result in most of the existing EQ components, cables, and splices being replaced on Unit 1. For those existing components that will not be replaced, the licensee has performed field verifications and record reviews to verify that the equipment was still EQ qualified. The licensee's piece parts qualification special program required that the maintenance records for the 27 saved components be reviewed in detail to verify that the EQ qualification had not been invalidated or degraded by the use of unqualified piece parts or sub-components during past maintenance activities. The inspectors examined a select sample of EQ components to confirm that both programs were being adequately implemented. Two Severity Level IV NCVs were identified for 1) failure to replace the O-rings after both transmitter housing covers were removed, and 2) failure to identify that a motor T-drain on a Limitorque operator had been plugged with paint. Both issues were documented by the licensee in PERs. The inspectors concluded the corrective actions were adequate. No further inspection of the EQ and Component/Piece Parts Special Program is planned.E1.8Special Program Activities - Instrument Sensing Lines (37550)

a. Inspection Scope

The instrument line program was developed for restart of Browns Ferry Unit 2 to address issues regarding installation of instruments sensing lines. The issues concerned potential violation of three basic design requirements: physical separation of redundant components; provision of sensing line slope; and specification of material 55quality requirements. TVA submitted the corrective action program for Unit 2 to addressthese concerns in a letter dated August 14, 1989. The Unit 2 scope and common instrument scope were based on evaluations of system calculations, the FSAR Chapter 14 safety analysis, emergency operating instructions, review of instrument related maintenance problems, and the master component equipment list. TVA concluded after completion of the instrument line evaluations that problems were limited to instrument slope. No cases were identified of inadequate physical separation of redundant components, and no cases were identified of inadequate material quality. The Unit 2 instrument sensing line program was reviewed and approved by NRC, as documented in Section 3.4 of NUREG-1232, Volume 3, Supplement 2. In letters dated February 13, 1991, and November 8, 1991, TVA submitted their action plan to resolve concerns related to instrument sensing lines for Browns Ferry Units 1 and 3. The basic approach was to use the same methodology used for Unit 2. NRC accepted the TVA action plan in a Safety Evaluation Report dated December 10, 1991. Eliminated from this Special Program were vendor supplied instruments, instrumentswith a process pressure greater the 100 PSIG, totally sealed capillary tubing, andinstruments without sensing lines. Previous inspections of the Unit 1 Instrument Sensing Lines Program are documented in NRC Inspection Report numbers 50-259/2006-007 and 50-259/2006-008.

b. Observations and Findings

The inspectors examined design change notices (DCNs) which specify correctiveactions to address instrument sensing line slope deficiencies, reviewed construction procedures, reviewed exceptions which resolved cases for areas where the installed instrument tubing did not meet the slope criteria, and the calculation completed by engineering to approve the exceptions. The inspectors also reviewed Problem Evaluation Reports (PERs) which documentedinstallation problems, and Post Issue Changes (PIC) which document changes from construction details shown on the design drawings. Final review of the PICs are being conducted by engineering. The drawings will be revised to incorporate the approved PICs. In the case when a PIC is not approved, a WO will be issued to perform additional field work to make any changes necessary so the affected supports meet design criteria. PICs reviewed by the inspectors were as follows: 63462, 67261, 67300, 67365, 67614, 68035, 68383 and 68400, deviations from design criteria for instrument sensing line slope. The inspectors walked down portions of the system instrumentation tubing in the Unit 1 reactor building listed below to examine the sensing line slope.

Sensing lines examined were as follows:*Torus water level instrument LT-64-159B sensing line, shown on Drawingnumbers 1-47E600-778 & -2660, modified per DCN-51245.*Containment inerting system instrument sensing line from containmentpenetration X-52 to the vertical rise of the line at elevation 587, shown on Drawing number 1-47E600-2614, modified per DCN 51201.

56*Primary containment isolation system (System 64) instrument sensing line fromcontainment penetration X-52 shown on Drawing number 1-47E600-2611, modified per DCN 51243.*Primary containment isolation system sensing line from instrument panel 25-307 to the vertical rise of the line at elevation 581 shown on Drawing number 1-47E600-2602, modified per DCN 51243.*Primary containment isolation system instrument PDT-64-137 sensing line frominstrument panel 25-306 to the vertical rise at elevation 529 shown on Drawing number 1-47E600-2603, modified per DCN 51243.*Primary containment isolation system instrument PT-64-34 sensing line frominstrument panel 25-34 to the vertical rise at elevation 528 shown on Drawing number 1-47E600-2604, modified per DCN 51243.*RHR system (System 74) instrument sensing lines from instrument panel 25-62 to the vertical rise at elevation 529 shown on drawing numbers 1-47E600-2577,

-2578, and -2586 through -2589, modified per DCN 51199.*RHR system instrument sensing lines from instrument panel 25-59 to the verticalrise at elevation 529 shown on drawing numbers 1-47E600-2591 and -2601, modified per DCN 51199.*RHR system instruments PS-74-51 and PT-74-51 sensing lines from instrumentpanel 25-59 to the vertical rise at elevation 528 shown on Drawing number 1-47E600-2590, modified per DCN 51199. *RHR system instrument sensing lines from instrument panel 25-59 to1-RTV-74-200A and -200B at 20" RHR pipe, shown on drawing numbers 1-47E600-2599 and -2600, modified per DCN 51199.*Reactor core insolation cooling (RCIC) system (System 71) instrument sensinglines from instrument panel 25-58 to 1-RTV-71-0020 at 6" RCIC pump discharge pipe at elevation 528, shown on drawing number 1-47E600-2575, modified per DCN 51236.*High pressure coolant injection (HPCI) system (System 73) instrument sensinglines from level switches73-57A and 57B to the vertical drop at elevation 535, shown on drawing number 1-47E600-2571, modified per DCN 51237.*HPCI system instrument sensing lines from instrument panel 25-63 topenetration R15194035 at elevation 534, shown on drawing numbers 1-47E600-2567, -2568, and -2569, modified per DCN 51237.The inspectors independently measured instrument line slope at numerous locationsusing a level to verify the modified instrument tubing met the slope specified on the DCN drawings, in PICs, or approved exceptions.

c. Conclusions

The inspectors determined that the licensee's program for correction of instrumenttubing slope issues complies with the design criteria, commitments to NRC, and NRC requirements. Based on observations, document reviews, and discussions with engineering personnel, the inspectors determined that actions completed by the licensee to address concerns with the Unit 1 instrument sensing lines complied with their commitments to NRC. Based on this inspection and previous NRC inspections documented in Inspection Report numbers 50-259/2006-007 and 50-259/2006-008, no further inspections are anticipated for this Special Program. No findings of significance were identified.E1.9Special Program Activities - Containment Coatings (37550)

a. Inspection Scope

The licensee committed to evaluate the drywell coatings under Section 14.3 of theirNuclear Performance Plan. The program includes inspections to identified unqualified coatings, calculation of the allowable quantity of uncontrolled coatings, and removal of uncontrolled coatings if required. Acceptance of the licensee's program for containment coatings by NRC is documented in NUREG-1232, Vol.3, Supp. 2, Section 3.7, Containment Coatings. Previous inspections of the Unit 1 Drywell Coatings are documented in NRC Inspection Report number 50-259/2006-006. Inspections of the licensee's activities for repairs of the torus coatings are documented in NRC Inspection Report numbers 50-259/2004-007, 2004-009, and 2005-006.

b. Observations and Findings

The licensee performed a walkdown inspection of the drywell in accordance with procedure numbers 0-TI-417, Inspection of Service Level I, II, III Protective Coatings,Rev. 4, and WI-BFN-1-MEB-03, BFN Unit 1 Primary Containment Coatings Inspection Plan, Rev. 1. The results of the inspections were documented on Notification of Indication forms and drywell coating inspection records which list components with unqualified coating and include the area and average dry film thickness of the existing unqualified coatings. If the type of coating on a piece of hardware was unkown or undocumented, it was considered unqualified. Work orders were prepared to address the deficiencies. Corrective actions included removal of the component with an unqualified coating, or reducing the thickness of the unqualified coating to less than three mils.

All unqualified coatings with a thickness greater than 3 MILs (0.003 inches)remaining in the drywell will be listed in the Unqualified Coating Log. The inspectors reviewed the uncontrolled coatings log. The quantity of uncontrolled coatings listed in the log as of December 21, 2006 was less than 49 square feet. Unit 1 restart acceptance criteria permit a maximum of 147 square feet of uncontrolled coatings. The inspectors performed a walkdown of portions of the drywell on Elevations 563 and584 to examine the coatings on the interior of the drywell vessel and on hardware installed inside the drywell. The inspectors verified the accuracy of the licensee's coatings walkdown inspection records by independently measuring the thickness of the unqualified coatings on several components, including recirculation pump 1A motor, 58monorail hoists, pull boxes, and various pipe support components. The inspectorsobserved painters removing the coatings from various components which had unqualified coatings exceeding a thickness of 3 MILs.

The inspectors reviewed Notification of Indications issued by the licensee's InserviceInspection staff which documented defective coatings on the drywell vessel and other defects such as the degraded moisture barrier between the Elevation 550 concrete floor and steel drywell vessel, areas of corrosion on the vessel, and presence of other defects such as grind marks or gouges in the vessel base metal. The moisture barrier will be completely replaced under WO 03-011002-003 prior to restart.

The inspectors reviewed Revision 6 of Calculation number CDQ0303970088 which evaluated the reduction in thickness of the Unit 1 drywell vessel plate due to minor surface corrosion. The calculation shows that the stresses in the drywell plate are less than ASME code allowable values.

c. Conclusions

The inspectors determined that the licensee's program for inspection of protectivecoatings in the drywell, and identification and documentation of deficiencies are consistent with their commitments to NRC. WOs were prepared to specify corrective actions.

Repairs are in progress to implement the corrective actions as specified in the WOs. Based on this inspection and a previous NRC inspection documented in Inspection Report number 50-259/2006-006, no further inspections are anticipated for this Special Program. No findings of significance were identified.E1.10Special Program Activities - Restart Test Program (37550)

a. Inspection Scope

The purpose of the Restart Test Program (RTP) for Unit 1 is to ensure the functionalintegrity of accident mitigation and safe shutdown systems. The various test requirements for Unit 1 are identified in 1-TI-469, Baseline Test Requirements. RTP activities for Unit 1 are being performed as an integral part of the return to service program, which includes post modification and post maintenance testing. The licensee's RTP for Units 1 and 3 was previously reviewed by the NRC staff and documented in a Safety Evaluation Report (SER) dated August 30, 1994. That SER, which did not specifically address Unit 1, concluded that the licensee's RTP provided adequate assurance that safety systems could fulfill their safe shutdown functional requirements and support the safe return to operation on Unit 3. At that time the licensee was requested, if the licensee subsequently decided to pursue restart of Unit 1, to submit similar documentation for testing planned for Unit 1. The licensee submitted the requested information for Unit 1 in a letter dated August 15, 2005.

b. Observations and Findings

TVA letter dated December 13, 2002, "Browns Ferry Nuclear Plant - Unit 1- RegulatoryFramework for the Restart of Unit 1," provided TVA's proposed regulatory framework for restart of Unit 1. The licensee stated that TVA's plan for the restart of Unit 1 was based 59on regulatory requirements, special programs, commitments, technical specificationimprovements, and TVA-identified deficiencies and concerns that were resolved prior to Units 2 and 3 restarts. The licensee also stated that the RTP for Unit 3 had utilized normal surveillance testing to a greater extent than done during Unit 2 restart. Also, additional administrative controls to ensure the status of the operating units was considered during planning and scheduling of restart testing, eliminated complete Loss of Off-site Power/LOCA tests and most drywell vibration testing and reduced the number of management assessment hold points during power ascension. The inspectors concluded that the licensee's RTP for Unit 1 is essentially similar to that used for Unit 3.Previous NRC reviews of the licensee's RTP are documented in Inspection reports 50-259/2004-08, 50-259/2004-09, 50-259/2005-06, 50-259/2005-07, 50-259/2005-08, 50-259/2005-09, 50-259/2006-06, 50-259/2006-07, and 50-259/2006-08. Another example of ongoing NRC review is also contained in Section E1.4 of this report. Activities inspected included review of Baseline Test Requirement Documents (BTRDs) and System Test Specifications (STS), observation of ongoing testing, and review of test results. Additionally, the Test Summary Reports (TSRs) for various important risk-significant systems were reviewed as part of the inspectors' ongoing oversight of the licensee's SRTS process. Although, the inspectors' observation and review of RTP activities will continue throughout the remainder of system acceptance testing and power ascension testing programs the inspectors concluded that the existing RTP provided adequate assurance that safety systems would fulfill their safe shutdown functional requirements and support the safe return to operation on Unit 1.

Based on this review no further program inspections are planned for the RTP Special Program.

c. Conclusions

The inspectors determined the licensee's RTP provided adequate assurance that safetysystems would fulfill their safe shutdown functional requirements and support the safe return to operation on Unit 1. NRC observation and review of RTP activities will continue throughout the remainder of the system acceptance testing and power ascension testing programs. However, no further program inspections are planned for the RTP Special Program.E1.11Special Program Activities - Long Term Torus Integrity Program & Large Bore Pipingand Supports (50090)

a. Inspection Scope

Summary of Long Term Torus Integrity Special Program The licensee followed the precedent of Units 2 & 3 which were restarted previously afterefforts to perform walkdowns, compare existing drawings, record and evaluate discrepancies, revise drawings and pipe stress and support calculations, issue DCNs, and modify the piping and the supports to meet the regulatory requirements. The licensee completed the process by using selected attributes for the structures inside the torus and attached piping systems outside the torus in accordance with Browns Ferry Nuclear Performance Plan dated August 1986 and Revision 2, dated October 1988, TVA letter to NRC dated April 29, 1991, Browns Ferry Nuclear Plant Program for 60Resolving Long Term Torus Integrity Issue Prior to the Restart of Units 1 and 3, andTVA letter to NRC dated December 13, 2002, Browns Ferry Nuclear Plant Unit 1 Regulatory Framework for the Restart of Unit 1. The licensee also performed the above process in order to meet the requirements of IE Bulletins 79-02, Pipe Support Base Plate Designs Using Concrete Expansion Anchors and 79-14, Seismic Analysis for As-Built Safety-Related Piping Systems.Summary of Large Bore Piping and Support Special Program The licensee followed the similar steps stated for the Long Term Torus IntegrityProgram.The inspectors reviewed Design Criteria BFN-50-C-7103, Structural Analysis andQualification of Mechanical and Electrical Systems - Piping and Instrument Tubing, Rev.

5, BFN-50-C-7100, Design of Civil Structures, Attachment A - General Design Criteria for the Torus Integrity Long Term Program, Rev. 16, and BFN-50-C-7107, Design of Class I Seismic Pipe and Tubing Supports, Rev. 7. The inspectors selected and performed independent walkdown inspections of 10 Long Term Torus Integrity Program pipe supports in the Main Steam Safety Relief Valve (MSSRV) and Residual Heat Removal (RHR) Systems to verify the field installed conditions as compared to as-built drawings. The inspectors reviewed two DCNs and two WO Packages in order to verify the adequacy of the design or modification, inspection, and implementation associated with the pipe supports. The independent support walkdown and document review of the DCNs and WOs were to verify adequacy and compliance with the design criteria, drawings, IE Bulletin 79-02, Pipe Support Base Plate Designs Using Concrete Expansion Anchors, and IE Bulletin 79-14, Seismic Analysis for As-Built Safety-Related Piping Systems. The inspectors reviewed PERs to verify adequacy of problem identification, resolution, corrective actions, and extent of condition reviews.

b. Observations and Findings

The inspectors walked down ten supports with licensee Quality Control (QC) examinersand engineers. The inspections were performed to evaluate the effectiveness of the licensee's walkdown, modifications, and repairs. The elements inspected included dimensions, sizes, diameters, symbols, identifications, spacing, and clearances formembers, anchor bolts, base plates, standard components, and welds. The supports walked down are listed below:Main Steam Safety Relief Valve (MSSRV) System Support No.Drawing Revision Nos.1-47B401-4Sheets 1 & 2, Rev. 003 & 0011-47B401-5Sheets 1 & 2, Rev. 003 & 002 1-47B401-15Sheets 1 & 2, Rev. 003 & 002 1-47B401-20Sheet 1, Rev. 001 1-47B401-50Sheet 1, Rev. 002 61Residual Heat Removal (RHR) System1-47B452-3268Sheet 1, Rev. 0011-47B452-3269Sheet 1, Rev. 001 1-47B452-3290Sheets 1 & 2, Rev. 001 1-47B452-3291Sheets 1 & 2, Rev. 001 1-47B452-3295Sheet 1, Rev. 002One problem identified was a measurement of 2 and 1/4 inches in the field for an offsetbetween the center lines of the spring can and support. The drawing required 2 and 3/4 inches. PER 112103 was issued by the licensee to correct the drawing. The inspectors reviewed DCNs 51341, System 071 Reactor Core Isolation Cooling(RCIC) and 51343, Systems 071 RCIC, 073 High Pressure Cooling Injection (HPCI),

074 RHR, and 075 Core Spray (CS) and associated WOs 03-005172 for DCN 51341 &

03-008332 for DCN 51343 for the Long Term Torus Integrity Program. The inspectors reviewed the DCNs for the scope, design, modification, or repair drawings, 50.59 screening review, procedures or calculations required to be revised or generated, and test or inspection requirements. The inspectors reviewed the WOs for installation, material, welder and weld data records, inspection records, and non-destructive examination records such as magnetic particle, liquid penetrant, or visual examination records. The inspectors also reviewed several PERs associated with these DCNs.Previous NRC inspections of Long Term Torus Integrity were documented in InspectionReports 50-259/2003009, 50-259/2003010, 50-259/2004011, 50-259/2005006, 50-259/2005009, 50-259/2006006, 50-259/2006007, and 50-259/2006008. During thecurrent reporting period and previous inspections the inspectors reviewed procedures,calculations, and inspections for the walkdown verification associated with finalacceptance of the modifications. The inspectors verified that required safety-relatedsystems for IE Bulletin 79-14 were included in the program. The inspectors concludedthat the licensee's corrective actions were effective. The inspectors identified nosignificant issues, indicating quality of work in this area has been adequate. Based on this and recent inspections, the inspectors concluded that at this time, no further inspections are anticipated for the Long Term Torus Integrity Special Program.Previous NRC inspections in the area of Large Bore Pipe Supports were documented inInspection Reports 50-259/2003009, 50-259/2003010, 50-259/2005006, 50-259/2005009, 50-259/2006006, 50-259/2006007, and 50-259/2006008. During thecurrent reporting period the inspectors performed a similar review as was performedabove for Long Term Torus Integrity. The inspectors verified that required safety-related systems for IE Bulletin 79-14 were included in the program. Based on this and recent inspections, the inspectors concluded that at this time, no further inspections areanticipated for the Large Bore Piping and Support Special Program.

c. Conclusions

The inspectors found that licensee performance was adequate in the Long Term TorusIntegrity Special Program based upon the independent walkdowns of 10 pipe supports; 62review of two DCNs and WOs; and review of a sample of PERs. No violations ordeviations were identified.Long Term Torus Integrity Special Program activities were adequately performed inaccordance with documented requirements. The inspectors concluded that at this time, no further inspections are anticipated for this Special Program.Large Bore Piping and Support Special Program activities were adequately performed inaccordance with documented requirements based on all previous inspections. The inspectors concluded that at this time, no further inspections are anticipated for the Special Program.E1.12Readiness for the Maintenance Rule - (62706)

a. Inspection Scope

On November 6-9, 2006, as part of the Brown's Ferry Unit 1 recovery, the inspectorsevaluated the licensee's plans and progress in instituting the requirements of the Maintenance Rule and verified conformance with 10CFR50.65 "Requirements for monitoring the effectiveness of maintenance at nuclear power plants". The inspection was completed in accordance with Inspection Procedure 62706.The inspectors reviewed the licensee's use of the System Pre-Operational Checklist(SPOC) process to integrate Unit 1 systems, structures and components (SSCs) into the operating unit's Maintenance Rule Program. The inspectors reviewed procedures and calculations; conducted interviews with the Maintenance Rule Coordinator, Component Engineering Supervisor, Unit 1 Transition Manager and system engineers; and performed walkdowns of Unit 1 SSCs. The inspectors verified a sample of Unit 1 SSCs were scoped adequately in accordance with 10CFR50.65(b), and reviewed the licensee's strategy for verifying adequate goals and performance criteria had been established to satisfy the requirements of 10CFR50.65(a)(1)/(2). The inspectors verified that the Unit 1 integration into the operating unit's Maintenance Rule program would include Performance Evaluations as required by 10CFR50.65(a)(3). The inspectors conducted interviews with Maintenance Planning personnel and reviewed the ORAM/SENTINAL program to ensure the licensee assessed and managed the risk of maintenance activities in accordance with 10CFR50.65(a)(4).

b. Findings

The inspectors verified selected SSCs were scoped adequately in accordance with10CFR50.65(b), and reviewed the licensee's strategy for verifying adequate goals and performance criteria had been established to satisfy the requirements of 10CFR50.65(a)(1)/(2). The inspectors verified that the Unit 1 integration into the operating unit's Maintenance Rule program would include Performance Evaluations as required by 10CFR50.65(a)(3) and that the licensee assessed and managed the risk of maintenance activities in accordance with 10CFR50.65(a)(4). No findings of significance were identified.

63E1.13Station Blackout (37550)

a. Inspection Scope

In preparation for the planned restart of Browns Ferry Unit 1 (and combined three-unitoperation), the inspectors reviewed the licensee's activities related to USI A-44, Station Blackout, for Unit 1. This included review of the Unit 1 compliance with the SBO Rule (10 CFR 50.63, "Loss of All AC Power"), as described in the NRC Supplemental Safety Evaluation (SSE) titled "Station Blackout - Browns Ferry Units 1, 2, and 3," dated September 16, 1992. In addition, the inspectors used the guidance in NRC Regulatory Guide 1.155, "Station Blackout." The inspection included a review of the licensee's ability to accomplish an integrated safe shutdown of all three units as described in the SSE.

One finding and violation is described below. Because this finding affected all three units, it also is documented in Units 2 and 3 Inspection Report 05000260,296/2006005.

b. Observations and Findings

b.1Station Blackout Duration and Mitigation StrategyDuring review of the SSE and related documents, the inspectors noted that TVA hadcommitted to inform the NRC in writing when SBO modifications (equipment and procedures) for Unit 1 (and three-unit operation) have been fully implemented, and prior to restart of Unit 1. This commitment was made in the licensee letter to the NRC dated October 15, 1992, in response to a request that was made in the NRC SSE. The licensee had not sent such a letter to the NRC. As described in the SSE and in the Updated Final Safety Analysis Report (UFSAR), thelicensee must be able to mitigate an SBO event on one unit and a loss of offsite power (LOOP) on the other two units for four hours with only three of the eight onsite emergency diesel generators (EDGs) operating in response to the event. The inspectors reviewed the licensee's calculations, procedures, electrical one-line drawings, and electrical load lists to verify that all necessary safe shutdown equipment for each unit would be powered during an SBO on Unit 1 and a LOOP on Units 2 and 3. The inspectors also discussed the mitigation strategy with operators and engineers and walked down selected components and operator actions in the plant.

The inspectors noted that only four of the eight EDGs automatically provide power to thefour normally available emergency equipment cooling water (EECW) pumps. The EECW pumps provide cooling water to all eight EDGs. The licensee's UFSAR and SBO analysis stated that two EECW pumps are required to provide adequate cooling for the EDGs. Subsequently, the licensee's engineers judged that the operating EDGs could run lightly loaded during the beginning of an SBO event if only one EECW pump was available to provide cooling water flow. However, some combinations of three EDGs could result in no EECW pumps being powered. Further, licensee analysis concluded that a heavily loaded EDG with no cooling water would overheat in about five minutes.

Similarly, the licensee's engineers judged that a lightly loaded EDG with no cooling water would overheat in about 15 to 20 minutes.

64The inspectors reviewed calculation MD-Q099-920053, "Station Blackout - Multi-UnitHVAC and DG Availability Analysis," Rev. 8, and abnormal operating instruction (AOI)0-AOI-57-1A, "Loss of Offsite Power (161 and 500 KV)/Station Blackout," Rev. 64. The inspectors found that the calculation, which described the SBO mitigation strategy, and the AOI were applicable to all three units. However, these documents possessed several shortcomings. They did not identify the need for urgent (i.e., time critical) operator action to ensure EECW flow to the EDGs. They did not evaluate how long the EDGs could operate without cooling water flow (the EDGs had no automatic over-temperature protection so operator action would be necessary to prevent diesel failure). And they did not evaluate how long it would take operators to perform other non-proceduralized but potentially urgent operator contingency actions. The inspectors found that the abnormal procedure did not include immediate operatoractions to ensure that operating EDGs would have adequate cooling water during a LOOP to prevent them from overheating. While not proceduralized, the licensee noted that two of the swing RHRSW/EECW pumps had a discharge motor-operated valve (MOV) that, if opened from the main control room, would quickly direct flow to the EECW system and cool the operating EDGs. However, the inspectors found that the electrical power supply for the MOV was provided by an EDG different than the one that powered the corresponding pump. Thus, the valve could possibly be without power requiring an operator outside the main control room to remotely open the valve. Power could be realigned to the valve from the main control room but these actions were not included in the AOI. Specifically, EDG B powered swing RHRSW/EECW pump C-1 for which normal power tocrosstie MOV FCV-67-49 was provided by 480V DG Aux Board A. This electrical board is normally powered from EDG A. Alternately, this board can be powered from EDG B by operator actions in the main control rooms but these time critical actions were not directed by the operating procedures. A similar situation existed for EDG 3D which powered swing RHRSW/EECW pump D-1, and crosstie MOV FCV-67-48 which was powered by DG Aux Board B. In addition, these valve manipulations would be successful only if EDG B or D was operating. 10 CFR 50, Appendix B, Criterion III, Design Control, requires that measures shall beestablished to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions.

Regulatory requirements of 10 CFR 50.63, "Loss of All AC Power," were to be implemented as described in the NRC Supplemental Safety Evaluation titled "Station Blackout - Browns Ferry Units 1, 2, and 3," dated September 16, 1992, and in the design basis as stated in the UFSAR Section 8.10, "Station Blackout." This included the ability of the site to mitigate an SBO on one unit and a LOOP on the other two units with only three EDGs operating in response to the event.Contrary to the above, the regulatory requirements and design basis for Station Blackoutwere not correctly translated into specifications, drawings, procedures, and instructions.

Calculation MD-Q099-920053, "Station Blackout - Multi-Unit HVAC and DG Availability Analysis," Rev. 8, and procedure 0-AOI-57-1A, "Loss of Offsite Power (161 and 500 KV)/Station Blackout," Rev. 64, did not ensure that the site could mitigate an SBO on one unit and a LOOP on the other two units with only three EDGs operating. The calculation 65and procedure did not ensure that the operating EDGs would have adequate coolingwater.

Because this failure to ensure that regulatory requirements and the design basis werecorrectly translated into specifications, drawings, procedures, and instructions is of very low safety significance and has been entered into the licensee's corrective action program as PERs 114913 and 114967, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy. It is identified as NCV 05000259/2006-09-06, Lack of Assured Cooling Water for Emergency Diesel Generators.

b.2Procedures and TrainingThe inspectors reviewed procedures and training to verify that they had beenimplemented for the design basis Unit 1 SBO event. This included verifying that procedures contained guidance for aligning the alternate AC power sources (the operating EDGs) to appropriate loads within the times stated in the SSER. It also included checking that the proceduralized limits on the suppression pool (Pressure Suppression Pressure and Heat Capacity Temperature Limits) would not require the operators to emergency depressurize the reactor vessel for a unit in an SBO and render the HPCI and RCIC systems inoperable before the end of the four-hour coping period.

During plant walkdowns, the inspectors also checked for adequacy of habitability, emergency lighting, and communications to support the operators' performance of the procedures. The inspectors identified no deficiencies of significance other than the one described in b.1 above. b.3Class 1E Battery Capacity and EDG LoadingThe inspectors reviewed the licensee's battery sizing calculations for multi-unit operationas well as unit battery load study, voltage drop, short-circuit, and battery capacity for varying combinations of unit loss of coolant accident (LOCA)/LOOP, Appendix R, and SBO scenarios. The inspectors found them to be consistent with IEEE Std-485 methodology. Analysis of the calculations concluded that sufficient unit battery capacityis available to meet and/or exceed the SBO coping duration time of four hours.

Inspectors verified that sufficient DC power would be available for the recovery of offsite power by the manual transfer of switchyard breaker DC control power (normally supplied from the station battery #4) to the safety-related unit battery #2. No deficiencies of more than minor significance were identified.Inspectors also reviewed calculations for EDG load studies for Units 1 and 2 andconcluded that EDG loading during an SBO and LOCA/LOOP scenario would not be excessive and within the maximum design ratings of the EDGs. During the review of the calculations, inspectors noted inconsistencies concerning Drywell Blower auto-loadingtime delays as depicted on drawing 1-45E779-3, "Wiring Diagram 480 V Shutdown Aux Power Schematic," Rev. 23. Further investigation revealed a drafting error in the design drawing. The licensee entered the condition in their corrective action program, (PER 114942) and immediately corrected the drawing. No deficiencies of more than minor significance were identified.

b.4Effects of Loss of VentilationThe inspectors reviewed licensee calculations and walked down selected areas in theplant to verify that during a design basis SBO ambient temperatures would support the operation of needed safe shutdown equipment. The inspectors observed that the HPCI and RCIC rooms had unobstructed openings below and above the level of the pumps that would support natural circulation cooling. No deficiencies of more that minor significance were identified.

b.5Containment IsolationThe inspectors reviewed licensee calculations and procedures for containment isolationin the event that it would be required. The licensee had screened out all but a few containment isolation flowpaths from needing further isolation, following guidance in NRC Regulatory Guide1.55, "Station Blackout." The containment isolation valves that were not screened out were all powered by DC MOVs that could be operated from the control room and were all included in the LOOP/SBO procedure. No deficiencies of more than minor significance were identified.

b.6ModificationsInspectors reviewed modifications implemented as a result of SBO Rule compliance aswell as modifications credited for SBO rule compliance. Scope of the reviews included DCN packages, 10 CFR 50.59 evaluations and/or screens, package scope, proposed licensing changes, and post-modification testing. There were no outstanding modifications required to comply with the SBO Rule. A list of documents reviewed are included in the attachments. No deficiencies of more than minor significance were identified.

b.7Quality Assurance (QA) and Technical Specifications (TS)Inspectors verified that SBO equipment is covered by an appropriate QA program perRG 1.155. Inspectors also verified that the ability to cross-tie normal AC 4 kV unit boards and 4 kV unit shutdown boards was not contrary to existing unit TS and/or design basis restrictions. No deficiencies of more than minor significance were identified. b.8EDG Reliability ProgramThe inspectors verified that the existing site EDG Reliability Program was in accordancewith the guidance of RG 1.155, Section 1.2. The licensee program contained requirements for routine surveillance testing, reliability monitoring, data collection, and maintenance for the EDGs, which ensure the target EDG reliability value of 0.95 is achieved. The inspectors discovered several administrative errors contained in the systems engineering reliability start failure and run failure logs. These errors were verified by inspectors to be conservative in nature and did not impact the EDG Reliability Target Values reported by the licensee to the NRC. The license entered the observation into their corrective action program (PER 114790) and immediately corrected the associated logs. No deficiencies of more than minor significance were identified.

c. Conclusions

The inspectors identified one nonconforming condition related to design control for SBO,as documented as a NCV in Section E1.13.b.1 above.

Also, the inspectors noted that the licensee had committed to send a letter to the NRC documenting compliance with the SBO rule for Unit 1 and combined three-unit operation, but had not yet sent such a letter to the NRC. The inspectors concluded that prior to restart of Unit 1, the licensee should completeadequate corrective action for the nonconforming condition. In addition, the licensee should send the appropriate letter to the NRC. USI A-44, Station Blackout, for Unit 1 will remain open pending completion of corrective actions.

E7Quality Assurance in Engineering ActivitiesE7.1Licensee Oversight of Unit 1 Recovery Activities (37550, 71152)

a. Inspection Scope

The inspectors reviewed licensee actions to address previously identified concernsassociated with the presence of uncontrolled duct tape on safety-related stainless tubing located in the drywell and foreign material exclusion in the Torus. The inspectors evaluated of the effectiveness of corrective actions associated with these documented deficiencies.

b. Observations and Findings

The inspectors had previously identified a deficiency in the licensee's control of duct tape(Unresolved Item 50-259/2006-08-02, Impact of Duct Tape on Instrument Tubing and ECCS Suction). The concerns were the presence of the potential for Intergranular Stress Corrosion Cracking (IGSCC) from chloride contaminated tape and foreign material exclusion in the Torus impacting the ECCS suction.

b.1Tape and Tape Residue on Stainless Instrument TubingDuring system walkdowns performed in the drywell, a section of one inch diameter CSsensing lines was noted to have whole pieces of duct tape and tape residue. This section of sensing line was associated with 1-PDIS-75-28 and 1-PDIS-75-56, just upstream of CS injection piping into the reactor vessel and is not able to be isolated in the event of a leak. Duct tape was also observed on other sections of small bore stainless piping on other systems. The licensee placed this issue into their correctiveaction program (PER 111681).Initial corrective actions associated with tape on the stainless sensing lines includedremoval of tape but tape pieces were not analyzed for chlorides.

PER 111681 was closed without adequate corrective actions. The inspectors had to prompt the licensee to analyze the chloride content of the tape pieces removed from the sensing lines. Based on discussions with licensee personnel the inspectors determined that the tape could 68have been present for as long as 20 years. Subsequent chemistry analysis determinedthat leachable chlorides exceeded the chemical requirements of standard material specification PF-1054 (chemistry report AG56961). Additionally, the core spray sensing lines were not evaluated for stainless steel corrosion impact from chloride impregnated tape (once leachable chlorides were analyzed as exceeding limits).The licensee's process specifications for handling and cleanliness requirements foraustenitic stainless steel, PS 4.M.1.1 and PS 4.M.4.1, set forth adequate requirements for procurement and use of pressure sensitive tape and external cleanliness criteria for stainless steel piping. The licensee's mechanical section instruction for cleanliness offluid systems, MSI-0-000-PRO001, also prescribes external cleanliness requirements,the same methods as PS 4.M.4.1, but referencing additional procedures. PS 4.M.4.1, Section 4.2.2, and MSI-0-000-PRO001, Attachment B, require components involved in modification or maintenance activities to be restored to their preactivity cleanness requirements by either of the following:Clean all affected areas with a demineralized water wipedown, and perform swipetest verification . . . orClean all affected areas with a demineralized water wipedown, and perform avisual inspection of the immediate and adjacent areas . . .PS 4.M.4.1 specifies the swipe test to be performed in accordance with Attachment 1 ofthe same specification. MSI-0-000-PRO001 specifies the swipe test to be performed per TI-92.Initial management oversight and corrective actions were insufficient in that promptingwas required before the tape was analyzed for chlorides. The licensee subjectively determined that the tape posed no problem.

Furthermore, an evaluation developed by the licensee, External Cleanliness of Unit 1 Stainless Steel Components, dated December 27, 2006, missed the intent of the issue by concentrating on the generic impact of tape on stainless steel versus specific procedural compliance with the core spray sensing line. Upon further prompting by inspectors, the licensee performed external cleanliness verifications as required by their existing procedures (the licensee initially planned to just perform a qualified visual inspection per their 0-TI-397 guidelines).

However, again inspectors prompted, that based on the previous tape sample failure, the licensee should perform the alternate method of physically verifying external surfaces of the core spray instrument line by sponge test swipes. Based on these discussions WO 07-710383-000 was initiated for sponge test swipes to be performed. The inspectors noted that the results of the sponge test swipes were negative for chlorides. Therefore, the inspectors concluded that although the licensee's initial corrective actions had failedto adequately address the issue, the final result was that there was no potential for damage to the stainless sensing lines.

b.2Foreign Material Exclusion in TorusAdditionally, duct tape was identified as panel edge moisture intrusion protection onnumerous electrical junction boxes during a torus walkdown, which was an ECCS foreign material exclusion (FME) concern. The licensee placed this issue into their corrective 69action program (PER 111684). The inspectors noted that corrective actions in the torusonly included tape removal from one vacuum breaker junction box and missed numerous junction boxes along the outside walkway. The inspectors discussed this concern with licensee management. Subsequently WO 06-723459-000 removed all tape on the other junction boxes. The inspectors will further inspect FME and cleanliness in the Torus during final closeout inspection prior to Unit 1 restart.

c. Conclusions

The licensee's initial corrective actions associated with a previously identified issueassociated with tape potentially contaminated with chlorides and a foreign material exclusion concern were not acceptable. Prompting was required before the tape was removed analyzed for chlorides and again before external cleanliness verifications were performed. However, based on final test swipe results which showed no chlorides, the inspectors concluded no potential for damage to the stainless sensing lines existed.

Unresolved Item (URI) 50-259/2006-08-02, Impact of Duct Tape on Instrument Tubing and ECCS Suction, is closed.E8Miscellaneous Engineering Issues (92701)E8.1(Closed) Generic Letter (GL) 92-04 and IE Bulletin (IEB) 93-03, Resolution of IssuesRelated to Reactor Vessel Water Level Instruments in BWRsAs discussed in NRC Information Notice 92-54, "Level Instrumentation InaccuraciesCaused by Rapid Depressurization," and Generic Letter 92-04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(f)," the staff was concerned that non-condensible gases may become dissolved in the reference leg of BWR water level instrumentation and lead to a false high level indication after a rapid depressurization event. GL 92-04 requested that addressees determine the impact of potential level indication errors after a rapid depressurization event on plant operation. GL 92-04 also requested that addressees take short term compensatory measures and provide the staff with plans for long term corrective actions, including any proposed hardware modifications. IEB 93-03 requested licensees to implement the measures and hardware modifications to ensure that potential level errors caused by reference leg de-gassing would not result in improper system response or improper operator actions during transients and accident scenarios initiated from reduced pressure conditions (Mode 3).In a response letter dated March 25, 1993, the NRC acknowledged receipt of TennesseeValley Authority's (TVA) response to GL 92-04, dated September 28, 1992 for Browns Ferry Nuclear Plant (BFN) Units 1, 2 and 3. The NRC found TVA's review and the commitment to implement the longer-term conclusions resulting from the BWR Owner's Group experimental testing and analytical development programs described in letter dated August 12, 1992, acceptable. The NRC staff evaluated the licensee's proposed long term modification plan and documented the results in a Safety Evaluation Report (SER) dated November 12, 1993. In a response letter dated April 20, 1994, the NRC acknowledged receipt of TVA's responses to IEB 93-03, dated July 30, 1993 and October 15, 1993, for BFN Units 1, 2 and 3. TVA committed to install a reactor vessel 70water level reference leg backfill system prior to restart of BFN Units 1 and 3. The NRCstaff considered TVA's responses acceptable. The inspectors reviewed the original correspondence documenting TVA's long termhardware modification to install a reactor vessel water level reference leg backfill system.

The inspector reviewed the modification package associated with DCN 51231 to verify the licensee had addressed the proper design constraints and captured corrective actions as a result of the implementation on BFN Units 2 and 3. The inspector performed a walkdown of the hardware to verify proper field implementation and to verify the design drawings were accurate (i.e, verified location of 0.5" piping or 1" piping being used). The procedure to properly control the backfill system was reviewed to verify adequate steps were in place for operator control. Additionally, procedures for removal and testing of the flow elements, rebuilding and maintaining check valves, and maintain and adjust the backfill system, were reviewed to verify the licensee had captured the adequate scope for maintenance and testing. The inspector reviewed purchasing invoices and manufacturer's records to verify the appropriate size filters were installed. The inspector also reviewed the licensing basis and design basis documents to verify the proper changes were made to reflect the modification. During this review, the inspector noted that the UFSAR denoted the backfill system for Units 2 and 3, however, not for Unit 1.

The modification package for Unit 1 should have recognized this necessary change. The licensee entered this issue into their corrective action program as PER 113672, DCN 51231 did not include a SAR Change Request in accordance with NADP-7 for section 7.10.3.1, Reactor Vessel Water Level Measurement.

Therefore, because the licensee's original submittal was adequate, the licensee has effectively implemented the design modification for the Reactor Vessel Level Indication (RVLIS) System, and because any implementation deficiencies would likely be detected by the licensee's oversight programs, this item meets the closure criteria established for Unit 1 recovery issues. No further inspection is expected regarding this item for Unit 1.

This item is closed.E8.2(Closed) GL 89-10, Safety Related Motor Operated Valve Testing and Surveillance This GL notified licensees that the NRC recommended that licensees develop andimplement a program to ensure that switch settings (torque, torque bypass, position limit, overload) for safety-related motor operated valves (MOVs) are selected, set, and maintained to confirm the MOVs will operate under design basis conditions. When the licensee had responded to GL 89-10 for Browns Ferry Units 2 and 3, Unit 1 was shut down in an extended outage. In their GL 89-10 response for Units 2 and 3, TVA committed to address GL 89-10 prior to restart of Unit 1. The inspectors determined that 51 valves are scoped under the licensee's GL 89-10program at each unit. For Unit 1, the licensee replaced 17 valve assemblies in full, and refurbished the remaining 34 valves while outfitting them with new operators. All 51 valves are to be static tested, of which 29 were complete at the time of inspection (22 remaining). 22 valves are scoped for differential (dynamic) testing, and 15 had been completed at the time of inspection (7 remaining). No testing was conducted over the inspection period for direct observation. The inspectors reviewed MOV program scope, design assumptions, and procedures; anda sample of MOV calculations and static and dynamic test reports. Selected licensee 71Problem Evaluation Reports (PERs) covering the duration of Unit 1 restart activitiesassociated with GL 89-10 MOVs were reviewed for evaluation of the licensee's corrective action program effectiveness. Some program implementing procedures were based on Units 2 and 3, and draft documents reflecting the inclusion of Unit 1 were previewed by the inspection team. Program calculations were reviewed for adequacy and accuracy.

Program support procedures were reviewed for technical accuracy and comprehensive coverage of their subject matter. The licensee's response to Information Notices 2003-15, 2006-03, and 2006-26, and other recent MOV operating experience, were also discussed. The licensee is implementing a Joint Owners Group (JOG) program as part of its response to GL 96-05 for long-term periodic verification of MOV design basis capabilities. The inspectors performed a walkdown inspection of selected MOVs, and concluded that the safety related MOVs that had been returned to service were in good condition. The inspectors identified a small number of minor MOV maintenance issues that the licensee agreed to address.The inspectors determined that, while the MOV program had not been fully completed, asignificant portion of the program had been implemented that allowed sufficient NRC staff review such that no further detailed MOV inspection activity is required for Unit 1.

The inspectors determined that this would appropriately address the issue for Unit 1.

Therefore, because this item is being corrected similarly to the Unit 2 and 3 solutions with the same process, and because any implementation deficiencies would likely be detected by the licensee's oversight programs, this item meets the closure criteria established for Unit 1 recovery issues. This issue is closed for Unit 1. E8.3(Closed) GL 96-01, Testing of Safety-Related Logic CircuitsThe NRC had documented a significant number of instances involving problems withlogic testing of safety-related circuits in various information notices. These information notices discussed events at various pressurized water and boiling water reactors. The examples of problems with logic testing cover a wide range of systems including safety injection system actuation, containment spray system actuation, residual heat removal system actuation, diesel generator load sequencing, and reactor protection system actuation. The NRC staff found that the failure to adequately test safety-related actuation logic circuitry was safety significant in that inoperable essential electric components required for automatic actuation of post-accident mitigation systems could go undetected for extended periods. The NRC staff noted that even in cases where surveillance testing of the logic circuits had not been complete, it was likely that only very small portions of the circuit had been omitted from the test. On the basis of the industry events, complexity of the logic, and contribution to the core damage frequency, the NRC staff issued GL 96-01, which instructed that licensees should review their surveillance procedures for the reactor protection system, EDG load shedding and sequencing, and actuation logic for the engineered safety features systems to ensure that complete testing was being performed as required by the technical specifications. In a letter dated September 29, 1997, Tennessee Valley Authority (TVA) submitted anotification of completion of GL 96-01 requested actions to the NRC for Browns Ferry Units 2 and 3. The letter communicated that TVA completed the requested actions outlined in GL 96-01 in conjunction with Browns Ferry's conversion to Improved Standard Technical Specifications (ISTS). The review identified two TS testing issues, inadequate 72surveillance testing for both the Control Room Emergency Ventilation and Residual HeatRemoval Loop I and II valves. The issues were documented in subsequent License Event Reports which were closed in respective NRC inspection reports. The NRC acknowledged completion of Browns Ferry Units 2 and 3 licensing actions in a letter dated June 28, 1999.

Examples of inadequate Unit 2 and 3 surveillance instructions were contained in Licensee Event Reports (LERs) 259/98-03, 260/97-02, 259/98-02, and 260/98-04. The NRC review of previous licensee actions associated with Units 2 and 3 were documented in Inspection Reports 50-259, 260, 296/98-03, 50-259, 260, 296/98-05, 50-259, 260, 296/98-07, and 50-259, 260, 296/98-09. The NRC considered the actions for Units 2 and 3 closed, however, licensee actions associated with Unit 1 remained open pending possible restart. The inspectors reviewed the original submittals documenting the safety logic testingprogram. Based on the systems distinguished in the GL and the Browns Ferry Units 2 and 3 responses, the inspector reviewed the scope of the Unit 1 96-01 program to verify adequacy. The inspector sampled system surveillance tests based on risk significance.

The inspector reviewed the draft procedures and completed tests for the systems to verify the licensee had captured the proper testing criteria as outlined in Units 2 and 3 and the respective Technical Specifications. The inspector verified the licenseedeveloped overlap drawings for review to identify proper logic, interlocks, and bypasses and inhibit circuits. The inspector reviewed Logic System Functional Testing and Surveillance Instructions to ensure the licensee was implementing the program as committed.

Additionally, the inspector reviewed corrective actions from the Unit 2 and Unit 3 GL 96-01 program implementation to ensure they were integrated into the Unit 1 implementation program as well. Discussions were conducted with licensee staff to verify Surveillance Instructions, maintenance procedures, and instrumentation procedures were consistent in identifying the important circuits and logic. Therefore, because the licensee based the Unit 1 96-01 implementation program on that of the NRC approved Browns Ferry Units 2 and 3 submittals, the licensee has effectively addressed the GL 96-01 requirements in the scope and subsequent surveillance procedures, and because any implementation deficiencies would likely be detected by the licensee's oversight and implementation programs, this item meets the closure criteria established for Unit 1 recovery issues. This item is closed.E8.4(Closed) GL 97-04, Assurance of Sufficient Net Positive Suction Head for EmergencyCore Cooling and Containment Heat Removal PumpsThis GL requested licensees provide information necessary to confirm the adequacy ofavailable net positive suction head (NPSH) for emergency core cooling (ECCS) and containment heat removal pumps. This item was previously reviewed by NRC as documented in Inspection Report 50-259/06-06. At that time final closure of this item was deferred until the Office of Nuclear Reactor Regulation (NRR) completed their review in this area and any safety evaluation reports (SERs), if required, were issued.

Subsequently, NRR completed their review in this area as documented in SER issued on July 27, 2006. Based on that review the staff concluded that the licensee's response to GL 97-04 for Unit 1 satisfied the required actions of the GL. Additionally, the information provided in the licensee's May 6, 2004, letter will be considered as part of the review of the adequacy of the available and required NPSH of the ECCS and containment heat removal pumps during the extended uprate review for Unit 1. The inspectors determined 73that no further actions associated with this GL were required for Unit 1. This issue isclosed for Unit 1.E8.5(Closed)Bulletin 96-03, Potential Plugging of Emergency Core Cooling Suction Strainersby Debris in Boiling Water ReactorsThe inspectors reviewed Bulletin 96-03, Potential Plugging of Emergency Core CoolingSuction Strainers by Debris in Boiling Water Reactor. Licensees were requested to implement appropriate procedural measures and plant modifications to minimize the potential for clogging of ECCS suction strainers by debris generated during a LOCA.

Additionally, this bulletin required licensees report to the NRC the extent of requested actions taken. This item was previously reviewed by NRC as documented in Inspection Report 50-259/06-06. At that time final closure of this item was deferred until NRR completed their review in this area and any SERs, if required, were issued.

Subsequently, the inspectors have determined that there are no concerns related to this Bulletin and that the licensee's actions previously reviewed in Inspection Report 50-259/06-06 are acceptable for restart of Unit 1. This issue is closed for Unit 1.E8.6(Closed) Inspector Followup Item (IFI) 50-259/95-55-01, Review of Licensee Final SafetyAnalysis Report (FSAR) Commitments for Continuous Air Monitors (CAMs) Associatedwith Units 1 and 3Through discussions with cognizant licensee representatives and a review of applicablerecords, the inspectors determined that the licensee's U1 CAMs were either out-of-service or in storage and were not able to meet certain FSAR commitments. Since U1 did not have any fuel and no significant safety issues were identified an IFI was left open for reviewing their functional status during future inspections. Since the opening of that IFI, the licensee had initiated plans to complete the construction of U1. During a review of calibration records, discussions with cognizant licensee representatives, and direct observations of selected U1 CAMs, the inspectors determined that the instruments had software and hardware electronics upgrades to include an LCD and keypad. In addition, the inspectors determined that the instruments had been appropriately calibrated. Based on those direct observations, discussions and reviews, the inspectors this item meets the closure criteria established for the Unit 1 recovery issues. This issue is closed for Unit 1.E 8.7(Closed) IE Bulletin (IEB) 79-02, Pipe Support Base Plate Designs Using ConcreteExpansion Anchors, and IEB 79-14, Seismic Analysis for As-Built Safety-Related PipingSystemsNRC review of licensee actions associated with these two bulletins is documented inSection E1.11 of this inspection report. The inspectors concluded that the licensee hadperformed the requirements in accordance with IE Bulletins 79-02 and 79-14. Therefore,these bulletins are closed for Unit 1.E8.8(Closed) 10 CFR 21 Report 2006-21-01, Potential Defect in OTEK Panel MetersDuring a TVA Corporate Engineering audit of the Southern Testing Services (STS)Software Verification and Validation report for the OTEK HI-Q Series digital meters a deficiency associated with the watchdog timer function was identified. The failure mode 74had previously been identified by STS as documented in Test Report S4000-RP-03. Specifically, a failed display processor would not be detected by the watchdog timer. The display processor failure would not update the displayed process information, either bargraph or digital display and the display would fail as-is. The frozen display inhibits the detection of the main processor failure except by cycling power to the panel meter. This condition was documented by the licensee in PER 111131. The inspectors reviewed PER 111131 and Functional Evaluation 41700, Rev 0, whichaddressed this problem. Based on this review and discussions with licensee personnel the inspectors determined that the licensee had decided to replace all of the affected meters installed on Unit 1 with modified meters. No OTEK meters had yet been installed on Units 2 or 3. Additionally, spare meters located in the warehouse would be replaced.

Meters being removed were to be returned to the vendor for modification and return to Browns Ferry for use as spares.The inspectors reviewed the listing of OTEK meters used on Unit 1. The inspectorsdetermined that a total of 51 of the affected meters had been installed on Unit 1 and that the WOs were issued to replace each of the affected meters. Only a limited number of those meters provide a safety-related function. The inspectors selected three safety-related meters assigned to System 64A, Primary Containment to determine status of corrective actions. Those meters were 1-TM-64-52B, Torus Temperature Indication; 1-TM-64-52CA, Drywell Temperature Indication; and 1-TIS-64-52AA, Drywell Temperature Indication. The inspectors verified that the WOs associated with these three safety-related meters were coded as "20" (required prior to SPOC I) on the System 64A SRTS-OIP. The inspectors reviewed WOs 07-710639-000, 07-710641-000, and 07-710643-000 which were issued by the licensee to replace the above 3 safety-related meters.

Each of these WOs were in the process of being worked at the end of the inspection period. The inspectors determined that this would appropriately address the issue for Unit 1. Therefore, because this item is being corrected and because any implementation deficiencies would likely be detected by the licensee's oversight programs, this item meets the closure criteria established for Unit 1 recovery issues. This issue is closed for Unit 1. E8.9(Closed) Unresolved Item (URI) 50-259/2006-006-01, Adequacy of SRTS ActivitiesThis item concerned weaknesses identified in the licensee's System Return to Service(SRTS) process. The weaknesses were originally identified by inspectors as a result of a focused inspection on a completed System Pre-Operability Checklist (SPOC) II system, Residual Heat Removal Service Water (RHRSW). Weaknesses included insufficient procedure guidance, insufficient operating plant staff involvement, inappropriate documentation and coding of open items, and inadequate training. The licensee had initiated their own self assessment and corroborated these NRC inspection findings. The licensee placed the deficiencies in their corrective action program and initiated improvements. The inspectors reviewed the status of licensee corrective actions in this area. The inspectors noted that 1-TI-437, System Return to Service (SRTS) Turnover Process for Unit 1 Restart was revised to reflect that the most current SRTS-Open Item Punchlist (OIP) is included in SPOC package review and approval; that all system coded open items are included in SRTS-OIP reviews and independent operating unit reviews were required; increased operating involvement by operating unit management, 75engineering, operations, and maintenance departments; separate Unit 1 and Unit 2/3management SPOC I and II review boards for each system; and clarification of system ownership from SPOC II to operability. Appropriate personnel involved in the SRTS process were trained, specifically system engineers. The inspectors noted that as the result of ongoing SRTS process improvements that documentation of open items, deferrals, and exceptions are generally more specific and accurate.

The inspectors noted that licensee management expectations were strengthened andbetter communicated resulting in increased operating unit ownership; increased operating unit organization participation in SPOC meetings, testing, and walkdowns; and systems being turned over in a much more ready condition resulting in fewer open items.

Based on review of corrective actions and independent inspections of risk significant systems, inspectors determined that licensee corrective actions were sufficient to meet their SRTS process requirements and did not violate NRC requirements. This item is closed.E8.10(Closed) URI 50-259/2006-008-02, Impact of Duct Tape on Instrument TubingThe licensee's resolution of this issue is discussed further in Section E7.1 of this report. This item is closed.E8.11(Discussed) Unresolved Safety Issue (USI) A-44, Station Blackout (SBO)This item is discussed further in Section E1.13 of this report. During that reviewconcerns associated with the licensee's compliance with the SBO rule for Unit 1 were identified. The licensee needs to complete corrective actions for the nonconforming condition. USI A-44, Station Blackout, for Unit 1 will remain open pending completion of corrective actions. III. MaintenanceM1Conduct of MaintenanceM1.1Inadequate Control Rod Drive (CRD) Scram Valve Maintenance Instruction

a. Inspection Scope

During the ongoing reviews of SRTS activities the inspectors reviewed licensee actionsassociated with the improper installation of Control Rod Drive (CRD) Hydraulic Control Unit (HCU) scram inlet and outlet valve diaphragms. The inspectors evaluated licensee actions to determine the significance of the problem and to verify that the issue was properly addressed under the licensee's corrective action program.

b. Observations and Findings

The inspectors reviewed the December 7, 2006, SRTS-OIP for System 85 CRD. Item111 referenced WO 06-725548-000 which documented a problem with HCU 34-27 scram inlet and outlet valve diaphragms being inverted. The diaphragms used in air operators 76for both scram inlet and outlet hydraulic control valves (370 total valves for 185 HCUs)are molded with a concave/convex profile. Industry concerns with leakage around the center stem hole led to an industry operating experience bulletin in June of 1988, and an update to General Electric (GE) Company's Service Information Letter (SIL) 457,

"Hammel-Dahl Scram Valve Diaphragm Leakage," with Supplement 1. This supplement provided a recommended procedure for diaphragm replacement, which included diaphragm orientation (i.e., concave side facing up) and increased spring stem nut torque. The SIL stated "note that diaphragms manufactured after January 1, 1990, may be installed according to either the original procedure or the following new one". The original vendor manual had a schematic of the valve showing diaphragm installation with the concave side up. The licensee incorporated these changes (in the current revision)into the GE Vendor Manual, GEK-9582C, Operation and Maintenance Instructions for Hydraulic Control Units (Part Nos 729E950 G1 Thru G6). However, these same changes were not incorporated into the site maintenance procedure, MCI-0-085-HCU001, Maintenance of CRD Hydraulic Control Units.All the HCUs were rebuilt by the licensee in 2004 and 2005, as part of a system-widerebuild, in accordance with Procedure MCI-0-085-HCU001, Revision 57. The procedure did not contain the guidance to install the diaphragm with the concave side up. A licensee audit of the procedure, as documented in PER 70219, had initially identified the discrepancy between the maintenance procedure and the vendor technical manual recommended procedure. The procedure was modified to reflect the requirement to install the diaphragm with the concave side up. However, the licensee subsequently identified three new additional examples where scram inlet/outlet valves were reworked with the diaphragms installed incorrectly. In November 2006, HCUs 34-27 and 30-55 scram valves developed air leaks in the diaphragms shortly after air pressure was applied. Hydraulic Control Unit 34-27 scram outlet valve was the first valve to develop an air leak (PER 114748) and the valve was repaired under WO 06-724834-000.

Approximately two weeks later, both the scram inlet and outlet valves for HCU 30-55 developed air leaks. The valves were disassembled and the diaphragms determined to be installed inverted (i.e., concave side facing down, PER 115040). Subsequently, the licensee again disassembled HCU 34-27 scram outlet valve in accordance with WO 06-725548-000 and found the diaphragm inverted, which was then corrected. The licensee determined that on November 3, 2006, the technician reinstalled the diaphragm inverted, contrary to Procedure MCI-0-085-HCU001, Revision 62, Step 7.1.4.14[2], which required the diaphragm to be installed concave side up. The licensee documented this error in PER 117046 and noted that the direction to install the diaphragm concave side up could be misinterpreted, therefore, requiring a potential procedure enhancement. The licensee indicated the enhancement would likely be an attachment that illustrates concavity.

Additionally, the licensee plans to evaluate and document acceptability of potentially inverted diaphragms and review the earlier failure to determine extent of condition.The licensee acknowledged that a significant number of scram inlet and outlet valvescould exist with the diaphragms installed inverted but additional valve inspections were not planned. Licensee personnel informed the inspectors that diaphragm orientation was not important to valve function and believed that installation of the inverted diaphragm did not contribute to diaphragm leakage. Furthermore, information contained in PERs 70219 and 117046, which address this issue, indicated that inverted diaphragms did not have an adverse impact on valve performance. Specifically, the licensee's evaluation that 77cited a 1988 industry operating experience bulletin stated although it appeared prudent toinstall the diaphragm in the proper orientation that diaphragm orientation had no adverse effect on valve performance or diaphragm leakage. Inspectors identified two examples of a violation of 10 CFR 50, Appendix B, Criterion V,associated with the maintenance on the scram inlet and outlet valves. 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings requires in part that,

"activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings." Specifically on January 3, 2005 and November 3, 2006, maintenance personnel used Procedure MCI-0-085-HCU001, Maintenance of CRD Hydraulic Control Units, Revisions 57 and 62 respectively, to rebuild HCUs 34-27 and 30-55. However, contrary to 10 CFR 50, Appendix B, Criterion V, the procedure did not adequately specify diaphragm installation for the scram inlet and outlet valves resulting in maintenance personnel incorrectly installing the diaphragms inverted. The licensee documented this deficiency in PER 117046. This violation is being treated as a Severity Level IV NCV consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000259/2006-09-07, "Inadequate Instructions for Maintenance on HCUs" .

c. Conclusions

The inspectors two examples of a Severity Level IV NCV for failure to provide adequateinstructions for maintenance on HCUs. Both issues were documented in the licensee's corrective action program. During a subsequent review, the licensee's corrective actions were determined to be adequate.IV. Plant SupportF1Fire ProtectionF1.1Special Program Activities - Fire Protection Improvements (37550, 64704)

a. Inspection Scope

On February 28, 2006, TVA submitted their Browns Ferry Nuclear Plant (BFNP) revisedFire Protection Program (FPP) for three unit operations. The inspectors examined DCNs associated with Unit 1 reactor building modifications to fire protection features. These modifications included upgrading general area fire detection systems, general area floor coverage fire sprinkler systems, addition of ventilation system fire dampers and additional fire barrier penetration seals. The inspectors also reviewed a DCN associated with a one-hour fire rated Thermo-Lag electrical raceway fire barrier system. The inspectors reviewed work completion/modification turnover package documentation,post-modification testing (PMT) instructions and return-to-operation requirements to evaluate equipment and system testing and operability. The inspectors also examined permanent and transient combustible materials and ignition source fire prevention and storage controls. Unit 1 pre-fire plan procedures were also reviewed.

78The inspectors planned to review the approved three unit Safe Shutdown Instructions(SSIs) to determine if the procedures were adequate to achieve and maintain safe shutdown (SSD). The licensee's three unit SSI verification and validation (V&V)packages were reviewed. Selected problem evaluation reports (PERs) for fire protection (FP) findings identified during the recent BFNP triennial FP inspections were reviewed.

The FP communications F2 and F4 radio systems and the Unit 1 backup control panel PMT were reviewed.

b. Observations and Findings

b.1Review of DCN Packages for Active Fire Protection Features The inspectors reviewed active fire protection feature DCNs 51368 and 51180 to verify area sprinklers of the Unit 1 Reactor Building and high pressure coolant Injection room sprinklers had been satisfactorily tested. The inspectors also reviewed the certified Record of Completion for the installation, operation, and testing of the fire alarm system for FA 25, intake pumping station and cable tunnel. The inspectors walked down portions of the Unit 1 reactor building fire detection and firesuppression systems to confirm that equipment and detector configurations were consistent with engineering drawings. In addition the inspectors reviewed NFPA Code deviation evaluation for the lack of sprinkler system drains for the Unit 1 Reactor Building elevation 565' sprinkler system to verify that the deviation would not adversely affect the design basis of the system.b.2Review of DCN Packages for Passive Fire Protection Features The inspectors reviewed DCNs 51190, 51208, and, 61563 for passive fire protectionfeatures of the Fire Protection Restart Special Program. The inspectors confirmed required fire damper field work had been satisfactory completed and tested. The inspectors performed walk downs to verify fire barrier penetration seals and fire doors were properly installed.b.3Review of Implementation of Fire Protection Administrative ControlsThe inspectors reviewed procedures SPP-10.7, SPP-10.10, SPP-10.11, and SPP-10.9which established the controls and practices to prevent fires and to control the storage of permanent and transient combustible materials and ignition sources during Unit 1 recovery activities. The inspectors walked down selected Unit 1 areas to verify the licensee controls for storage of permanent and transient combustible materials were adequate.

b.4Review of Unit 1 Fire Brigade Pre-Fire Plan The inspectors walked down selected Unit 1 pre-fire plans and fire response procedures to determine if appropriate information was provided to identify safe shutdown equipment, instrumentation and to facilitate suppression. The inspectors compared the pre-fire plans with as-built configuration and the Fire Hazards Analysis (FHA) to verify 79that pre-fire plan drawings, fire protection features and potential fire conditions describedin the FHA were consistent. The inspectors determined that the pre-fire plan layout drawings and strategies covered all subjects required by the fire protection program.

However, the licensee had previously identified a number of deficiencies in the pre-fire plan layout drawings and strategies for Unit 1 areas affected by configuration changes.

The licensee plans to conduct a thorough review and update of pre-fire plans for Unit 1 areas in PER 117818.

b.5Review of BFNP Appendix R Three Unit Safe Shutdown ProgramA September 21, 2006, NRC letter required the three unit 10CFR50 Appendix R Safe Shutdown Instructions (SSIs) be completed by January 1, 2007. TVA November 15, 2006, letter indicated that the combined three unit SSIs would be issued by December 31, 2006, and placed on administrative hold. As of January 26, 2007, the three unit SSIs were not in a final approved status. The three unit SSIs were still undergoing changes and were not under a revision control system consistent with issued procedures.

Additional design changes which have the potential to change the three unit SSIs were not complete. Ongoing Unit 1 labeling work will require further SSI revision. The three unit SSIs were not ready for final NRC review. NRC deferred the decision onthe feasibility of the 10CFR50 Appendix R Section III.G.2 local OMAs until TVA notifiesNRC that the work has been completed.Following the initial V&V of 0-SSI-16, TVA added two additional Auxiliary Unit Operators(AUOs) to the minimum shift complement to accomplish the required OMAs. This is documented in procedure OPDP-1, Conduct of Operations, Rev. 0007. The inspectors reviewed selected weekly shift staffing and confirmed that the minimum number of AUOs listed in OPDP-1 were assigned to each shift.The inspectors reviewed the criteria for performing a reverification of SSI changes. Theinspectors found that changes to the basis documents, functional changes, and changes to OMAs of 30 minutes or less required an updated V&V. As of January 26, 2007, a single change associated with the SSIs has reached this threshold. In SSI-3-3 an OMA was added to ensure Containment Atmosphere Dilution emergency lighting was restored.

The inspectors confirmed the procedure change was in the current unissued version of revision 0.The inspectors reviewed several V&V packages for current unissued revisions of thethree unit SSIs. The V&V consisted of three sections OMA, lighting and communications. These were reviewed separately. The inspectors reviewed the OMA portions described in selected SSI V&Vpackages. The times annotated on the V&V packages were not consistently documented. The inspectors concluded that the documentation detail was insufficient to determine the OMA's mission times without discussions with the AUOs who performed the V&V. The inspectors determined that the V&V packages prepared for the three unit SSIs did not completely demonstrate local OMA feasibility in an auditable form. Verification of SSD emergency lighting and 80communications adequacy was contained in the PMT portions of theimplementing DCNs. The inspectors reviewed SSD emergency lighting PMT. The emergency lightingPMT demonstrated SSD lighting was adequate. TVA stated that the PMT fulfilled the emergency lighting V&V requirements. The inspectors also reviewed SSD communication V&V. The licensee tested F2 and F4 radio systems from SSI OMA locations to each main control room and the backup control panels.

However, the V&V did not demonstrate communication capability using battery back-up power under design basis fire conditions. The licensee identified the communications system DCN was accepted as complete without completing all field work. The inspectors noted that the test of the communication system failed from several locations, because the antenna was not correctly installed.Additionally, the inspectors reviewed calibration data for instruments and controls on theUnit 1 backup control panel. The inspectors reviewed a sample of the few instruments and controls installed and tested and found no problems; however, most of the instruments and controls on the backup control panel have not been tested. This includes all the Main Steam and RCIC instruments and controls. The inspectors were unable to complete the review of this panel since much of the work is incomplete.

c. Conclusions

Overall implementation of restart testing and System Return to Service activities for fireprotection detection and suppression systems was acceptable. This conclusion was based on reviews of work completion/modification turnover package documentation, completed PMT packages, and completed surveillance testing documentation associated with active fire protection features. (F1.1.b.1)The inspectors' review of modification design packages associated with upgrades topassive fire barrier systems concluded that the design changes were appropriately implemented and were acceptable. The DCNs adequately addressed the changes needed to restore Unit 1 to current fire protection program requirements. (F1.1.b.2)The fire prevention control program for storage of permanent and transient combustiblematerials and ignition sources met fire protection program requirements. Transient fire loads associated with maintenance, modifications, and construction activities were being adequately controlled by the licensee's fire protection program. (F1.1.b.3)Fire brigade pre-fire plan layout drawings and strategies adequately covered all subjectsrequired by the fire protection program. However, some pre-fire plan layout drawings and strategies for Unit 1 areas have been significantly affected by Unit 1 recovery changes and require updating to incorporate new modifications. This activity was documented and tracked in the licensee's corrective action program. (F1.1.b.4)On January 22 - 26, 2007, NRC reviewed the TVA BFNP Unit 1 fire protection specialprogram for closure. The intent was to inspect the restart readiness of the Unit 1 fire protection systems and the final version of the three unit SSIs, The inspectors determined most of the fire protection hardware modifications were implemented. The 81fire protection hardware, with the exception of the Unit 1 backup control panel and unit 1communication systems, was judged to be ready for restart. The SSI's had pending revisions which could potentially affect the V&V results. In order for NRC to complete the final review, TVA must have either issued the three unit SSI's in final, or have the draft three unit SSIs covered by a procedure revision control process. (F1.1.b.5)NRC deferred the decision on the feasibility of the 10CFR50 Appendix R Section III.G.2local OMAs until TVA notifies NRC that the SSIs have been completed. No further inspections are planned for the fire protection systems with the exception of Thermo-Lag, SSIs, Communications, and the Backup Control Panel. The Fire Protection Special Program will remain open.No violations or deviations were identified 82V. Management MeetingsX1Exit Meeting SummaryOn February 28, 2007, the resident inspectors presented the inspection results toMr. Masoud Bajestani and other members of his staff, who acknowledged the findings.

Although some proprietary information may have been reviewed during the inspection, no proprietary information will be identified in the final inspection report.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

M. Bajestani, Vice President, Unit 1 Restart

R. Baron, Nuclear Assurance Manager, Unit 1

M. Bennett, QC Manager, Unit 1

D. Burrell, Electrical Engineer, Unit 1

P. Byron, Licensing Engineer

J. Corey, Radiological and Chemistry Control Manager, Unit 1

W. Crouch, Nuclear Site Licensing & Industry Affairs Manager

R. Cutsinger, Civil/Structural Engineering Manager, Unit 1

B. Hargrove, Radcon Manager, Unit 1

K. Hess, SWEC Project Director

R. Jackson, Bechtel

R. Jones, General Manager of Site Operations

J. Lewis, Integration Manager

G. Little, Restart Manager, Unit 1

J. McCarthy, Licensing Supervisor, Unit 1

R. Moll, Mechanical Engineering and Systems Engineering Manager, Unit 1

B. O"Grady, Site Vice President

J. Schlessel, Maintenance Manager, Unit 1

J. Valente, Engineering Manager, Unit 1INSPECTION PROCEDURES USEDIP 35301QA of Preoperational Test ProgramIP 37550Onsite Engineering

IP 37551Engineering

IP 51053Electrical Components and Systems - Work Observation

IP 60705Preparations for Refueling

IP 62706Maintenance

IP 64704Fire Protection

IP 70301Preoperational Test Procedure Review

IP 70315Preoperational Test Witness

IP 71111.08Inservice Inspection Activities

IP 71111.17Permanent Plant Modifications

IP 71111.20Refueling and other Outage Activities

IP 71111.23Temporary Plant Modifications

IP 71152Identification and Resolution of Problems

IP 72500BInitial Fuel Loading Procedure

IP 92701Follow-up

IP 50090Pipe Support and Restraint Systems

A-2Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened259/2006-09-03URICriteria Was not Adequately Defined To Ensure DivisionalSeparation for Cables Were Maintained (Section E1.5)Opened and Closed259/2006-09-01NCVInadequate Instructions for Testing ECCS Logic (Section E1.4)

259/2006-09-02NCVMeasures Were Not Adequate to Assure that Cables fromOpposite Divisions Were Separated (Section E1.5)259/2006-09-04NCVT-Drain On Limitorque Operator Has Been Plugged With Paint(Section E1.7)259/2006-09-05NCVTransmitter Cover O-Ring Not Replaced As Required By QMDS(Section E1.7)259/2006-09-06NCV Lack of Assured Cooling Water for Emergency Diesel Generators (Section E1.13)259/2006-09-07NCVInadequate Instructions for Maintenance on HCUs (Section M1.1)

Closed92-04GLResolution of Issues Related to Reactor Vessel Water Levelinstruments (Section E8.1)93-03BUL Resolution of Issues Related to Reactor Vessel Water Levelinstruments (Section E8.1)89-10GLSafety Related Motor Operated Valve Testing and Surveillance(Section E8.2)96-01GLTesting of Safety-Related Logic Circuits (Section E8.3)

97-04GLAssurance of Sufficient Net Positive Suction Head for EmergencyCore Cooling and Containment Heat Removal Pumps (Section

E8.4)96-03BUPotential Plugging of Emergency Core Cooling Suction Strainersby Debris in Boiling Water Reactors (Section E8.10)95-55-01IFIReview of Licensee Final Safety Analysis Report (FSAR)Commitments for Continuous Air Monitors (CAMs) Associated with

Units 1 and 3 (Section E8.6)

A-3Attachment79-02BULPipe Support Base Plate Designs Using Concrete ExpansionAnchors (Section E8.7)79-14BULSeismic Analysis for As-Built Safety-Related Piping Systems(Section E8.7)06-21-01P21Potential Defect in OTEK Panel Meters (Section E8.8)

06-06-01URIAdequacy of SRTS Activities (Section E8.9)

06-08-02URIImpact of Duct Tape on Instrument Tubing (Sections E7.1, E8.10)

DiscussedA-44USIStation Blackout (Sections E1.13, E8.11)

A-4Attachment

LIST OF DOCUMENTS REVIEWED

Section O8.1:

Fuel Load readinessProcedures and Standards1-TI-270, Fuel Load and Restart Prerequisite Checklists, Rev 3, Appendix A, Fuel Loading Prerequisite Checklist, Rev 30-GOI-100-3C, Fuel Movement Operations During Refueling, Rev 60 0-TI-147, Fuel Loading, Rev 10

1-OI-75, Core Spray System, Attachment 1 Valve Lineup Checklist, Attachment 2 Panel Lineup Checklist, and Attachment 3 Electrical Lineup Checklist, Effective date 7-19-061-OI-78, Fuel Pool Cooling and Cleanup System, Attachment 1A Valve Lineup Checklist, Attachment 2A Panel Lineup Checklist, and Attachment 3A Electrical Lineup Checklist,Effective dates 3-03-06 (Attachment 2A 7-28-06).0-OI-23 Attachment 1A; Residual Heat Removal Service Water System Valve Lineup ChecklistUnit 1;

Effective Date June 23, 20060-OI-67 Attachment 1A; Emergency Equipment Cooling System Valve Lineup Checklist Unit 1;Effective date July 03, 20061-OI-63 Attachment 1; Standby Liquid Control System Valve Lineup Checklist; Effective DateAugust 4, 20061-OI-70 Attachment 1; Reactor Building closed Cooling Water System Valve Lineup Checklist;Effective Date December 4, 20061-OI-69 Attachment 1; Reactor Water Cleanup Operating Instruction Valve Lineup Checklist;Effective Date September 29, 2006BP-339, Attachment A; Browns Ferry Nuclear Plant Department Readiness Review Process ForUnit 1 Restart; revision 1, dated February 1, 2006SPP-9.3, Appendix C Checklist Technical Evaluation U1C7 Core Loading and

TVA-COLR-BF1C7, Rev 0/1SPP-5.8, Summary of Planned Transfer Operations 1-74Drawings:1-47E814-1, Flow Diagram Core Spray System, Rev 231-47E855-1, Flow Diagram Fuel Pool Cooling System, Rev 25

1-47E610-23-1; Mechanical Control Diagram RHR Service Water System; dated September 23,20061-47E858-1; Flow Diagram RHR Service Water System; dated November 17, 2005

1-47E859-1; Flow Diagram Emergency Equipment Cooling Water; dated December 5,

2006

1-47E610-67-1; Mechanical Control Diagram Emergency Equipment Cooling Water System;dated January 21, 20061-47E854-1; Flow Diagram Standby Liquid Control System; dated August 31, 2006

1-47E610-63-1; Mechanical Control Diagram Standby Liquid Control System; dated September23, 20061-47E822-1; Flow Diagram Reactor Building Closed Cooling Water System; dated November11, 20061-47E610-70-1; Mechanical Control Diagram Reactor Building Closed Cooling Water System;dated November 8, 2006

A-5Attachment1-47E810-1; Flow Diagram Reactor Water Cleanup System; dated July 17, 20061-47E837-1; Flow Diagram Reactor Water Cleanup Demineralizer; dated October 18, 2006Problem Evaluation Report (PERs)94993;

BFN-SCH-06-002 Self-Assessment in Outage and Scheduling Area

104320 Action3; Change Management Plan Site Engineering 3-Unit Readiness, dated November 15,

2006116587; Configuration Control; dated December 14, 2006

108662; NSRB Meeting No. 296 Action Item; dated October 20, 2006

116686; PM WO Coded To RCV; dated December 14, 2006

108689; ITEL Screening of WOs For Shared or Common Systems; dated October 18, 2006

106895; Maintenance Rule Implementation For U1; dated October 31, 2006

109597;

BFN-SCH-06-004 AFI 1; dated September 27, 2006

113236; Control Rod Drive System - Neutron Monitoring; dated December 8, 2006

115033; Self-Assessment response; dated December 8, 2006Misc DocumentsSystem Health Report Cards for all reload required systemsUnit 1 Restart Outage Safety Plan System Scoping Milestone Reports List of Work Order Backlog for RHR System Just-In-Time Training for

DCN 51107, Unit 1 Annunciator System, including attendance sheets

NSRB Meeting Minutes dated December 14, 2006, for Meeting No. 297 on November 21, 2006

PORC Meeting Minutes No. 8477 for meetings on December 11 and 13, 2006

50.59 Screening Review

TVA-COLR-BF1C7, Rev 0

Memo L32061130800 Mitchell to Keck, Browns Ferry Unit 1 Cycle 7 - Full Core Loading Patternfor Core Loading VerificationNSAC 164L Guidelines for BWR Reactivity Control During Refueling, April 1992

Site Engineering 3-Unit Readiness Implementation Plan; dated November 27, 2006

Change Management Plan Outage & scheduling 3-Unit Readiness; dated October 13, 2006

CIG-19; Chemistry Interim Guideline Transition Plan Support Of three Unit Operation; Rev 0,dated June 29, 2006Radiation Protection 3-Unit readiness Implementation Plan; dated November 2, 2006

RCI 37; Unit 1 radiological Protection Start-up readiness; revision 1, dated October 1, 2006

Comprehensive Operational readiness Change Management Plan For Three Unit Operation;Final RevisionBFN Excellence Planning; Current Actions by Due Date for: Outage and Scheduling; SelectedDate Range January 9, 2006 thru January 31, 2007All Inclusive List of Fuel Load Required Actions; dated September 11, 2006

Punchlist Item Number PL-06-3687

Change Management Plan Corrective Action Program 3-Unit Readiness; dated October 30,2006Change Management Plan Operations 3-Unit readiness; dated October 30, 2006

Maintenance Training 3-Unit Readiness; transition Plan For BFNPER

107676 - TransitionTraining Provided By Unit 1/SWEC Personnel; dated October 25, 2006BFN-SCH-06-002; Self-Assessment Report; dated December 5-9, 2005

BFN PEG Three Unit Transition Plan; dated November 6, 2006

A-6AttachmentOperations Staffing White Paper For 3-Unit TransitionEmergency Preparedness Information Bulletin Number 2006-005; dated December 11, 2006

BFN-LIA-07-SSO1, Snapshot Self-Assessment Report, Unit 1 Core reload Readiness; datedNovember 14-21, 2006Section E1.1:

Temporary ModificationsProcedures, Guidance Documents, and Manuals0-TI-405, Plant Modifications and Design Change Control, Rev. 00-TI-410, Design Change Control, Rev. 1

SPP-9.5, Temporary Alterations, Rev. 6TACFs1-84-058-92, System 92, Neutron Monitoring System1-84-066-92, System 92, Neutron Monitoring System

1-84-074-74, System 74, RHR

1-84-100-99, System 99, RPS

1-85-012-92, System 92, Neutron Monitoring System

1-85-100-56, System 56, Temperature Monitoring System

1-85-021-77, System 77, Radwaste

1-85-023-64D, System 64D PCIS

1-85-024-85, System 85 CRD

1-85-027-35, System 35 Main Generator H2 System

1-86-024-74, System 74 RHR

1-89-001-90, System 90 Radiation Monitoring System

1-84-073-01, System 01 Main Steam

1-84-053-03, System 03 Reactor Feed Water

1-84-056-03, System 03 Reactor Feed Water

1-85-022-066, System 66 Offgas, Recombiner, and Charcoal Filter

1-05-004-044, System 44 Building Heating, and System 70 Reactor Building Closed Cooling Water

1-06-008-079, System 79, Fuel HandlingDesign Change Notices51080, Reactor Protection System, Electrical - Control Bay, System

9951081, Main Steam, Standby Liquid Control, and Containment, Instrumentation and Control -

Reactor Building, Systems 01, 63, and 64

51085, ECCS Analog Trip Unit Power Supplies, Electrical - Control Bay, System 256

51108, Primary Containment Isolation System, Electrical - Control Bay, System 64D

51152, Core Spray System, Electrical and Mechanical - Reactor Building, System 75

51158, Neutron Monitoring System, Electrical - Drywell, System 92

51199, Residual Heat Removal, Electrical and Mechanical - Reactor Building, System 74

206, Control Rod Drive, Electrical and Mechanical - Reactor Building, System 85.

A-7AttachmentSection E1.2:

System Return to Service ActivitiesProcedures, Guidance Documents, and Manuals1-TI-331, Post Accident Sampling Procedure, Revision 00001-TI-437, System Return to Service (SRTS) Turnover Process for Unit 1 Restart, Rev 17 & 22

1-TI-452, Restart Test Program Test Requirements, Revision 5.

1-TI-516, RBCCW Cooling System Flow Balance, Revision 2

1-OI-70, Reactor Building Closed Cooling Water System, Revision 37

1-OI-85, Control Rod Drive System, Revision 1 and Attachments 1, 2, 2A, 2B, 3, and 4

1-OI-92, Source Range Monitors, Rev. 6

1-OI-92A, Intermediate Range Monitors, Rev. 8

0-SI-4.6.H-2B, Functional Testing of Bergen-Paterson, Anchor/Darling or Fronek HydraulicsSnubbers, Revision 50-SI-4.6.H-2A, Functional Testing of Mechanical Snubbers, Revision 4

1-SI-4.7.A.2.G-3/70, Primary Containment Isolation Valve Local Leak Rate Test: Reactor BldgClosed Cooling Water System, Revision 01-SI-3.3.8.C, ASME Section XI System Pressure Test of The Residual Heat Removal SystemLoop II (ASME Section III Class 2), Rev. 11-SI-3.3.6, ASME Section XI Pressure Test of Core Spray System

1-SI-3.1.8, Core Spray System Data Evaluations

1-SR-3.6.2.5.2(I), Residual Heat Removal System Loop I Drywell Spray Header Air Test, Rev 2,October 8, 20061-SR-3.6.2.5.2(II), Residual Heat Removal System Loop I Drywell Spray Header Air Test, Rev.1, October 5, 20060-SR-3.6.2.4.2, Torus (Suppression Pool) Nozzle Test, Rev. 3, May 12, 2006

1-SR-3.5.1.6(RHR I-COMP), RHR Loop I Comprehensive Pump Test, Rev. 2

1-SR-3.5.1.6(RHR

II-COMP), RHR Loop II Comprehensive Pump Test, Rev. 3

1-SR-3.3.5.1.5, Core Spray System Loop II Minimum Bypass Flow Switch Calibration

1-SR-3.3.5.1.5, Core Spray System Loop I Minimum Bypass Flow Switch Calibration

1-SR-3.3.5.1.3, Core Spray System Pump Discharge Pressure ADS Permissive Calibration

1-SR-3.3.3.2.1(CS I), Backup Control Panel Testing

1-SR-3.3.5.1.3, Core Spray System Logic Time Delay Relay Calibration (Loop 1)

1-SR-3.3.5.1.6(CS I), Core Spray System Logic Functional Test (Loop 1)

1-SR-3.3.1.8(11), Reactor Protection System Manual Scram Functional Test, Revision 0.

1-SOI-3/68, Temporary Alignment of Reactor Vessel Level and Pressure Instrumentation,Revision 00001-SR-3.3.1.1.13(4A), Reactor Protection and Primary Containment Isolation Systems LowReactor Water Level Instrument Channel A1 Calibration 1-L-3-203A, Revision 00011-SR-3.3.1.1.13(4B), Reactor Protection and Primary Containment Isolation Systems LowReactor Water Level Instrument Channel B1 Calibration 1-L-3-203B, Revision 00011-SR-3.3.1.1.13(4C), Reactor Protection and Primary Containment Isolation Systems LowReactor Water Level Instrument Channel A2 Calibration 1-L-3-203C, Revision 00011-SR-3.3.1.1.13(4D), Reactor Protection and Primary Containment Isolation Systems LowReactor Water Level Instrument Channel B2 Calibration 1-L-3-203D, Revision 00011-SR-3.3.5.1.5(RWL A), Core and Containment Cooling Systems Reactor Low Water LevelInstrument Channel A Calibration 1-L-3-58A, Revision 00011-SR-3.3.5.1.5(RWL B), Core and Containment Cooling Systems Reactor Low Water LevelInstrument Channel B Calibration 1-L-3-58B, Revision 0001

A-8Attachment1-SR-3.3.5.1.5(RWL C), Core and Containment Cooling Systems Reactor Low Water LevelInstrument Channel C Calibration 1-L-3-58C, Revision 00011-SR-3.3.5.1.5(RWL D), Core and Containment Cooling Systems Reactor Low Water LevelInstrument Channel A Calibration 1-L-3-58D, Revision 00011-SR-3.3.5.1.2(ATU B), Core and Containment Cooling Systems Analog Trip Unit FunctionalTest, Revision 00001-SR-3.3.5.1.4(A), Core and Containment Cooling Systems Reactor Low Pressure InstrumentChannel A Calibration 1-P-3-74A, Revision 00001-SR-3.3.5.1.4(B), Core and Containment Cooling Systems Reactor Low Pressure InstrumentChannel B Calibration 1-P-3-74B, Revision 00001-SR-3.3.1.1.9(IRM A), Intermediate Range Monitor Channel A Calibration, Rev. 1

1-SR-3.3.1.1.3(IRM's), Intermediate Range Monitor Functional Test with Reactor Mode SwitchNot in Run Position, Rev. 01-SR-3.3.1.1.12, Reactor Protection System Mode Switch in Shutdown Scram & Logic SystemFunctional Test, Rev. 41-SR-3.10.4(B) Verification of Surveillance Requirements for Single Control Rod Withdrawal-Cold Shutdown (Multiple Rod Testing), Rev. 1MCI-0-085-HCU001, Maintenance of CRD Hydraulic Control Units, Revision 62

1-BFN-BTRD-099, Baseline Test Requirements Document, Revision 5.

PMTI-51080, Unit 1 Reactor Protective System (RPS), Revision 0.

PMTI-51080, Unit 1 Reactor Protective System (RPS), Revision 1.

PMTI-51080, Unit 1 Reactor Protective System (RPS), Revision 3.

PMTI-51080, Unit 1 Reactor Protective System (RPS), Revision 4.

PMTI-51195-STG01, Functional Testing of RBCCW Components and Alarms Revision 2CalculationsNDQ0999910033, Safe Shutdown Analysis, Revision 22MDQ1-070-2002-0064, MOV 1-FCV-070-0047, Operator Requirements and Capabilities,Revision 2.CDQ1-070-2002-0884, Pipe Stress Analysis of Stress Problem N1-170-52R and - 55R, Revision5CDQ1-070-2002-0356, Summary of Piping Analysis Problem N1-170-1R, Revision 10

CDQ1-070-2002-0357, Summary of Piping Analysis Problem N1-170-2R, Revision 08

CDQ1-075-2002-0867, Pipe Stress Analysis of Problem

NI-175-53R and -54R

CDQ1-075-2002-0822, Small Bore Piping Evaluation of Problem NI-175-97R

CDQ1-075-2002-0822, Small Bore Piping Evaluation of Problem

NI-175-100RDrawings1-47E822-1, Flow Diagram Reactor Building Closed Cooling Water System, Revision 381-47E822-2, Flow Diagram Outage Drywell Chiller System, Revision 2

1-47B464-460-1, Mechanical RBCCW System Pipe Support, Revision 3

47W922-5, Mechanical Cooling and Ventilation Drywell, Revision 4

1-47E811-1, Flow Diagram Residual Heat Removal System, Rev. 31

105E2202, Suction Strainer, Rev. 1

1-E20, TVA Containment Vessel Browns Ferry Unit 1 Suction Strainer Erection

ISI-0363-C SH. 1, Residual Heat Removal Shutdown Supply Support Locations, Rev 1

1-ISI-0363-C SH. 4, Residual Heat Removal Shutdown Supply Support Locations

A-9Attachment1-ISI-0363-C SH. 5, Residual Heat Removal Shutdown Supply Support Locations1-ISI-0363-C SH. 8, Residual Heat Removal Shutdown Supply Support Locations, Rev 1

1-ISI-0363-C-11, Residual Heat Removal Shutdown Supply Support Locations

1-47B452S0183, Piping Support Orientation

1-47B452S0191, Piping Support Orientation

1-47B452H0038, Piping Support Orientation

1-47B452H0037, Piping Support Orientation

1-47B452R0036, Piping Support Orientation

1-47B42H0071, Piping Support Orientation

1-47E610-75-1, Mechanical Control Diagram - Core Spray System

1-47E814-1, Flow Diagram - Core Spray System

47B407-93, Mechanical Vent, Drain and Test Connection Configuration - Power House

Reactor Building Unit 10-45B891-80, Conduit and Grounding, Cable - Conduit Seal EGS QDC Method1-45E641-3, Wiring Diagram I&C Power System Schematic

1-45E620-5-1, Wiring Diagram Annunciator System Key Diagram

1-45E620-6-2, Wiring Diagram Annunciator System Key Diagram

1-45E620-9, Wiring Diagram Annunciator System Key Diagram

1-45E671-1,2,3,4, Wiring Diagram RPS Trip Units DIV IA

1-45E671-7,8,9,10, Wiring Diagram RPS Trip Units DIV IIA

1-45E671-13,14,15,16, Wiring Diagram RPS Trip Units DIV IB

1-45E671-19,20,21,22, Wiring Diagram RPS Trip Units DIV IIB

0-45E701-2, Wiring Diagram Battery BD 1, Panel 8-12 Single Line

1-47E610-43-5, Mechanical Control Diagram - Sampling and Water Quality System

1-47E867-3, Flow Diagram - Sampling and Water Quality System, Revision 1

1-47E860-1, Flow Diagram - Containment Inerting System, Revision 23

1-47E610-74-1A, Mechanical Control Diagram - Residual Heat Removal System, Revision 26

1-47E1610-76-3, Mechanical Control Diagram - Containment Inerting System, Revision 9

1-47E811-1, Flow Diagram - Residual Heat Removal System, Revision 31

1-47E610-3-2, Mechanical Control Diagram - Reactor Feedwater System, Revision 10

1-47E610-64-1, Mechanical Control Diagram - Primary Containment System, Revision 53

1-47E803-1, Mechanical Flow Diagram - Reactor Feedwater, Revision 15

1-47E610-68-1, Mechanical Control Diagram - Reactor Recirculation System, Revision 14

1-47E610-3-1, Mechanical Control Diagram - Reactor Feedwater System, Revision 16

0-47E820-1, Flow Diagram Control Rod Drive Hydraulic System, Revision 32

1-47E610-85-1, Mechanical Control Diagram CRD Hydraulic System, Revision 19

1-47E610-85-2, Mechanical Control Diagram CRD Hydraulic System, Revision 12

1-47E610-85-4, Mechanical Control Diagram CRD Hydraulic System, Revision 3

1-47E610-85-5, Mechanical Control Diagram CRD Hydraulic System, Revision 5

1-47E810-1, Flow Diagram Reactor Water Cleanup System, Revision 17

1-47E820-2, Flow Diagram Control Rod Drive Hydraulic System, Revision 6

1-47E820-6, Flow Diagram Control Rod Drive Hydraulic System, Revision 6

1-47E820-7, Flow Diagram Control Rod Drive Hydraulic System, Revision 12

1-47E844-2, Flow Diagram Raw Water Cooling, Revision 46Problem Evaluation Report (PERs)115160, RBCCW flow to recirculation pumps seal coolers less than 30 gpm115215, RBCCW flows to Drywell Cooler and NRHX outside acceptance criteria

A-10Attachment115098, Total RBCCW flow out of tolerance113860, Unit 1 Panel 9-3 Housekeeping Problems

113863, Loose Clearance Tag from 1-3-33

113791, System 075 Core Spray SRTS OIP

2264, Potential 10CFR21 Consolidation Power Supply

113292, Missing Valve Handles/Conduit Interferences for DCN 51231

111131, Watchdog Timer Error for OTEK Meters

87536 ICRDS Revision Discrepancy for DCN 51079

115758 IRM Relay Failures

89054 U1 Reactor IRM Dry-Tube location 48-13

115955 Neutron Monitoring Half Scram on Unit 1

113121 Neutron Monitoring Penetration Connectors

116835 Tie wraps on Neutron Monitoring System

116837 Under Vessel Drain Not Entirely Covered

236, System 85, CRD

45425, System 85, CRD

203, System 85, CRD

68136, System 85, CRD

219, System 85, CRD

84377, System 85, CRD

93619, System 85, CRD

277, System 85, CRD

114178, System 85, CRD

114298, System 85, CRD

115040, System 85, CRD

115955, System 85, CRD

115972, System 85, CRD

117046, System 85, CRDMiscellaneous DocumentsBFN-50-7070, General Design Criteria Document, Reactor Building Closed Cooling System,Revision 09

Updated Final Safety Analysis Report Section 10.6 Reactor Building Closed Cooling Water System Amendment 21

MOVATS Test Data 1FCV7047

Licensed Operator Training OPL171, RBCCW system System Scoping Milestone Report (11/30/06): Open System 70 work orders

1-BFN-BTRD-074, Residual Heat Removal (RHR) System (074), Rev. 5

BFN-50-7064A, Browns Ferry Nuclear Plant Primary Containment System, Rev. 20

System Pre-Operability Checklist (SPOC II) - System 074, November 10, 2006

System Return to Service - Open Item Punchlist, November 13, 2006

TVA Browns Ferry Unit 1 Torus ECCS Strainer Final Torque Video, March 2, 2005

TVA Browns Ferry Unit 1 Torus ECCS Header Inspection, March 1, 2005

Unit 1 Technical Specifications Unit 1 Technical Specifications Bases Unit 1 Updated Final Safety Analysis Report (UFSAR)

System Plant Acceptance Evaluation Package - Core Spray System System Return to Service - Open Item Punch List - Core Spray System, 10/08/06

A-11AttachmentDetailed Design Criteria Document,

BFN-50-7075, Core Spray System1-TI-439, ITEL (Integration Task Equipment List)

1-TI-437, System Return to Service (SRTS) Turnover Process for Unit 1 Restart Unit 1 Core Spray System Flush Plan Test Summary Report, 1-BFN-BTRD-075

1-TI-452, Attachment 1, Restart Test Program Test Requirements

1-STS-075, System Test Specifications Temporary Alteration Control Form, TACF# 1-04-011-64D

Lesson Plan OPL171.028, Reactor Protection System (RPS), 05/30/2004.

Updated Final Safety Analysis Report Section 7.2, Reactor Protection System.

Test Summary Report, 1-BFN-BTRD-099.

Unit 1 Technical Specifications, 3.3.1.1, Reactor Protection System (RPS) Instrumentation.

Unit 1 Technical Specifications Bases, 3.3.1.1, Reactor Protection System (RPS)

Instrumentation.

System Plant Acceptance Package, System 99, Revision 0

System Plant Acceptance Package, System 99, Revision 1

System Plant Acceptance Package, System 99, Revision 2

System Return to Service - Open Item Punchlist (SRTS-OIP)

SE-ITEL-410 for system 043-01, December 18, 2006.

SRTS-OIP

SE-ITEL-430 for system 043

System Pre-Operability Checklist (SPOC II) - System 043-01, Post-Accident Sampling,December 10, 2006System Plant Acceptance Evaluation Package, System 043, Sampling and Water Quality,January 20, 2006Browns Ferry Nuclear Plant (BFN) Units 1,2, and 3 Technical Specifications (TS) Change 423

Unit 1 System 043-01 SPOC II Review Board Meeting Agenda Unit 1 Reactor Vessel Level Instrumentation System needed for fuel load (RVLIS-FL) SPOC IIBoard AgendaSRTS-OIP

SE-ITEL-430 for system 003

PMTI-51080 (Sys 099), Reactor Protection System (RPS) Functional Test (Includes DCN 51243)

Updated Final Safety Analysis Report Section 7.8 Reactor Vessel Instrumentation Updated Final Safety Analysis Report Section 7.10 Feedwater Control System Updated Final Safety Analysis Report Section 10.17

BFN-50-7092, General Design Criteria Document, Neutron Monitoring System, Rev. 7

FSAR Section 7.5, Neutron Monitoring System Various Technical Specifications related to the Neutron Monitoring System, TS 2.0, TS 3.1, TS

3.2, and TS 3.3

Various Technical Requirement Manual Specifications related to the Neutron Monitoring System,

TR 3.3.4, and TR 3.3.5

1-BFN-BTRD-092, Baseline Test Requirements Document Neutron Monitoring System

RIMS #W82-060126-002, Neutron Monitoring System Fuse Inspection/Replacement Fuse Program for Unit 1

Design Criteria Document,

BFN-50-7085, Control Rod Drive System, Revision 12

Detailed Flush Plan, 1-DFP-085-A, Revision 1

General Electric Operation and Maintenance Instructions,

GEK-9582C, Hydraulic Control Unit Part Nos. 729E950 G1 Thru G6, December 1987

General Electric Service Information Letter 373, For Scram Valve Opening Air Pressures General Electric Service Information Letter 457, "For Hammell Scram Valve Diaphragm Leakage, September 28, 1987

2AttachmentGeneral Electric Service Information Letter 457, "For Hammell Scram Valve DiaphragmLeakage, Supplement 1, June 12, 1990

Interoffice Memo, W87-061027-008, Complete the Fuse Inspection Program for Unit 1 Prior to Unit 1 Startup, dated 10/16/2006

Interoffice Memo, W87-061101-005, BFP870829D01 in Support of System 085 SPOC II, dated11/1/06

Interoffice Memo, W87-061219-001, Partial Completion of BFP870308 in Support of 085 SPOC, Dated 12/19/06

Mechanical Corrective Instruction,

MCI-0-085-HCU001, Maintenance of CRD Hydraulic Control Units, Revision 62

Lesson Plan, ICT157.000, Rod Gallery Familiarization, Revision 6

Lesson Plan OPL171.005, Control Rod Drive (CRD) Hydraulics, Revision 14

System 085 Control Rod Drive Cleanliness Verification Summary System Pre Operability Checklist (SPOC II) - System 085, Control Rod Drive, December 12,

2006

System Return to Service - Open Item Punchlist, December 7, 2006

Trico, Technical Information Sheet, "Glass, LS, or SS Opto-Matic Oilers," May 2002

Updated Final Safety Analysis Report Section 3.4, Reactivity Control Mechanical DesignUnit 1 Restart Status Report, November 29, 2006

Unit 1 System 085 SPOC II Review Board Meeting Agenda Unit 1 Technical Specifications and Bases 3.1.1, Shutdown Margin (SDM), 3.1.3, Control Rod Operability, 3.1.4, Control Rod Scram Times, 3.1.5, Control Rod Scram Accumulators, 3.1.6, Rod Pattern Control, 3.3.2, Control Rod Block Instrumentation Work Orders 98-015387-000, 04-711094-001, 04-714744-000, 04-714744-007, 04-714745-000, 04-714745-007, 04-717246-000, 04-720512-000, 04-722972-000, 05-711809-000, 06-721386-000, 06-

23827-000, 06-724834-000, 06-725195-000, and 06-725548-000DCNs51080, Primary DCN for system

9951081 STG3, cable additions and deletions from systems 3 & 68

51082 STG 1, cable additions between ICS and system 99

51082 STG 3,

PIC 61535 adds Trip Relay SOE points to ICS

51085

STG 10, 12, 16, Breaker, fuse and cable replacement

51090

STG 20 & 41, Breaker replacement and testing

51091

STG 15 & 20, Fuse replacement

51096 STG 8, changes SCRAM reset data plate and light color

51107

STG 16, 17, 19, 33, Annunciator system modifications

206 STG 2, Disables low SCRAM pilot header pressure trips

219, Adds cables and wiring between PNL 1-9-15, 1-9-17 and 1-9-4, system 68

231 STG 2 & 3, Cable replacement between systems 3 & 9

241, Disables Main Steam Line High Rad SCRAM and PCIS isolation

243 STG 3,4,5,6,8 Replaces RPS analog power supplies

51148, U1 Recovery Drywell Mechanical System 70

51660, Unit 1 Restart, Electrical Lead DCN Box Seals (Outside Drywell) Reactor Building

A-13AttachmentSection E1.3 Area Turnover ActivitiesProceduresBusiness Practice

BP-338, Area Turnovers from Recovery Unit 1 Restart Project, Rev 3PERs115568, Identified NE Corner Room Walkdown Deficiencies115691, Identified SW Corner Room Walkdown Deficiencies

117818, Pre-fire Plan Upgrades

118402, NRC Walkdown of 4KV Board Rooms and U1 Reactor El 621

118403, Ladders Hung Inappropriately

118433, Out-of-date Hot StickDrawings1-47B403-4-1, Mechanical Primary Containment System Pipe Support1-47B403-5-1, Mechanical Primary Containment System Pipe Support

1-4BE1025-3, Miscellaneous Steel Pipe Anchor Framing Core Spray Pump A

1-4BE1025-5, Miscellaneous Steel Pipe Anchor Framing Core Spray Pump C

Browns Ferry Radiological Survey Maps M0125, M0127, M0130, M0132, Pre-Fire Plan Numbers

RX1-519, RX1-519NW

0-45B891-1, Conduit & Grounding Waterproofing & Sealing Details of Electrical Equipment

0-45B891-6, Conduit & Grounding Cable - Conduit Seal Rosemount Corp Method0-45B891-9, Conduit & Grounding Cable - Conduit Seal Rosemount Corp Method0-45B891-10, Conduit & Grounding Acceptable Weep Holes for Conax Seal Installation

0-45B891-22, Conduit & Grounding Waterproofing & Sealing Details of Electrical Equipment

0-45B891-25, Conduit & Grounding Cable Supporting Fire Seal

0-45E891-31, Conduit & Grounding Waterproofing & Sealing Electrical Enclosures List

0-45E891-32, Conduit & Grounding Waterproofing & Sealing Electrical Enclosures List

0-45B891-80, Conduit & Grounding Cable - Conduit Seal EGS QDC Method

0-45B891-81, Conduit & Grounding Acceptable Weep Holes for EGS QDC InstallationMiscellaneous DocumentsG-29B-S01, ASME Section III and Non-ASME Section III (Including AISC, ANSI/ASME B31.1,and ANSI B31.5) Bolting Material Licensee Area Turnover Schedules

BFN-50-7071, Reactor Core Isolation Cooling General Design Criteria

BFN-50-715, Environmental Design General Design Criteria

BFN-50-727, Environmental Qualification General Design Criteria

BFN-50-789, Normal, Standby, and Emergency Lighting Systems for Main Control Rooms General Design Criteria

TVA Nuclear Power General Engineering Specification G-43, Snubbers

LCDS 306, Grinnell Corporation Load Capacity Data Sheets for 306N and 307N Mechanical Snubbers

LCDS DR1459, Bergen-Paterson Load Capacity Data Sheets for Standard Supports Qualification Maintenance Data Sheets

TBK-001

A-14AttachmentSection E1.4:

Restart Test ProgramProcedures and StandardsTechnical Instruction 1-TI-469, Baseline Test Requirements, Rev. 1SSP-3.1, Corrective Action Program, Rev. 9

SPP-8.1, Conduct of Testing, Rev. 3

SPP-8.3, Post Modification Testing, Rev. 6

SSP-9.5, Temporary Alterations, Rev. 7

SSP-10.3, Verification Program, Rev. 1.

SPP-10.2, Clearance Procedure to Safely Control Energy, Rev 9Test Summary Reports:1-BFN-BTRD-575, 4KV AC Distribution1-BFN-BTRD-64B, Reactor Building Ventilation System

1-BFN-BTRD-70, RBCCW System

1-BFN-BTRD-74, RHR System

1-BFN-BTRD-85, CRD System

1-BFN-BTRD-99, RPS SystemSurveillance Instructions 1-SR-3.5.1.9, Simulated Auto Actuation of Loop I RHR Pumps, Rev 51-SR-3.3.1.1.12, Reactor Protection System Mode Switch in Shutdown Scram and Logic SystemFunctional Test, Rev 2

1-SR-3.5.3.4, RCIC System Rated Flow at Low RPV Pressure, Rev 2

0-SR-3.8.1.6, Common Accident Signal Logic Test, Rev 16

0-SR-3.8.1.9(A), Diesel Generator A Emergency Unit 1 Load Acceptance Test, Rev 1

0-SR-3.8.1.9(C), Diesel Generator C Emergency Unit 1 Load Acceptance Test, Rev 1Work Orders 06-725112-000, Relanding of U2 Accident Signal to CAS LogicPERs115833, Auto initiation lockout of Unit 2 Loop I ECCS pumps during Unit 1 ECCS testing

115837, Auto initiation lockout of Unit 2 Loop I ECCS pumps during Unit 1 ECCS testing

116801, Practice of Double Booting Relay Contacts

114498, Invalid Actuation of U1/2 Emergency Diesel Generators

114496, Surveillance Restoration Error

114679, Peer Checking CAS Test Equipment Installation

114422, Relay Failed to Energize

114721, Failure to Perform As-Left Valve Position and Perform IV

A-15AttachmentSection E1.5: Special Program Activities - Cable Installation and Cable SeparationComponents Inspected for Separation RequirementsTable A.11PC270I, 1PC370I, 1PC504, 1PC290I, 1PC282I, 1V2450II, 1V2451II, 1V2452II, 1V2453II,1PC516, 1PC282I, 1PL5615, 1PL5612, 1PL5619, 1PL5632, 1PL5625, 1PL5628, 1PC337,1PC5051, 1ES5284, 1ES239IITable A.21PC665-IA, 1PC666-IB, 1PC668-IIA, 1PC669-IIB, INM76/IB, INM84/IB, INM92/IIB, INM101/IIB,1ES205-I, 1A2274, 1A5219, 1ES205-IS2, 1ES1433-IS2, 1ES1434-IS2, 1PL2061,1PL2062,

1PL2063Procedures and StandardsBFN-50-728, DCD Physical Independence of Electrical Systems, Rev.16BFN-50-758, Power, Control, and Signal Cables for Use in Class 1 Structures, Rev.15

G-38, Installation, Modification and Maintenance of Insulated Cables Rated up to 15,000 Volts, Rev.20

G-40, Installation, Modification and Maintenance of Electrical Conduit, Cable Trays, Boxes, Containment Electrical Penetrations, Electric Conductor Seal Assemblies, Lighting andMiscellaneous Systems, Rev.15CalculationsEDQ1-999-2002-0023, Cable Ampacity Calculation for Safety Related V5 Power Cables Outsidethe Drywell, Rev.16

ED-Q0001-920589, Division I Cables Requiring Separation to Maintain HPCI-ADS

Independence, Rev. 9

ED-Q19992003061, Internal Cable Separation Analysis, Rev. 01

ED-Q0999-910078, External Cable Separation Analysis, Rev.14DCAs51083-00151083-003

51083-004

51158-078

51158-080

51158-082

51158-084

2160-004

2160-005

2160-007

2160-008

2160-009

2160-010

A-16AttachmentDCNs51143, Main Steam System and Standby Liquid Control System51211, BFNP U1 Restart-Electrical Lead

DCN-System 001

222, 480V RMOV BD 1B, System-074

243,

51158, Replace all Source Range Monitor, Intermediate, Local Power Range Monitor Cables51081, Modifications to Panel 1-9-17 (T35738), Panel 1-9-5

51083, Cable/Termination Issues for HPCI, PCIS, and Containment Air Dilution in Control BayArea.

51095, Implement Modifications to Panel 1-9-4 to resolve Identified HEDs

51190, Reactor Building Ventilation/Secondary Containment

51194,

51195, RBCCW System 070 and PCCS System 080

2160, Fuel Pool Cooling System mods to Support System SPOCWalkdown Packages ReviewedLSWDP-BFN-1-ELEC-312, Verify Internal Separation of Cables 1RP426-IIIB & 1RP209-IIIA inPNL 9-16, Rev. 0

LSWDP-BFN-1-ELEC-353, Verify Internal Separation of Cables 1PC665IA, 1PC666IB,

1PC669IIB, & 1PC668IIA, Rev. 0

LSWDP-BFN-1-ELEC-354, Verify Divisional Separation of Internal Wiring and Devices in 1-

PNLA-009-0003, Rev. 0

LSWDP-BFN-1-ELEC-357, Verify Divisional Separation of Division II Power Source for FCV-74-

47, Rev. 0

WDP-BFN-1-EEB-074-VCD-01, Walkdown Data for RHR "B" Pump motor cable ES2625-II, Rev.4

LSWDP-BFN-1-ELEC-425, Verify That All Cables Exiting Conduits on Attached list Enter Same Division Tray, Rev. 0PICs Reviewed60667, Barrier Enclosures63505, Cable 1PC665IA, 1PC666IB, 1PC669IIB, 1PC668IIA

51088, Cable 1V2453II

51995, Cable 1V2452II

212, Cable 1PC516

61167, Cable 1ES6011I

61068, Cable 1PP9857

227, Cable 1ES5404I

63623, Cable 0ES173I

63713, Cable 0ES125I

222,

A-17AttachmentProblem Evaluation Reports Reviewed107116, Cables incorrectly pulled107138, Non Divisional cables routed between Division I and Division II trays

107488, Conduit without bushing to protect cables

113286, V2/V3 Voltage Separation Issue

113926, Cable Tray Cover Installation Problems for DCN 51227

113374, Damage Voltage Divider in Cable Trays

113566, ICRDS Note does not Reflect Installed Configuration In Existing Plant Tray

117774, Intruder Cables in Panel 25-31 found as Unacceptable

115701, FME Violation - Raceway covers not installed

113374, Damage Voltage Divider in Cable Trays

115700, Conduit TaggingProblem Evaluation Reports Generated115696, Duct tape used to secure tray cover

115697, Cables ran outside of Tray

115699, Divisional Separation Violation of Cables in Conduit 1ES832-I115700, Conduits Incorrectly labeled in 250V RMOV BD 1A

115701, FME Violation - Raceway Covers not Installed

117921, Conduit 1ES5659-IS2 is not Completely Enclosed in Top Hat

117831, Conduit 1ES5659-IS2 is incorrectly labeled as 1ES5659-IIDrawings0-45N808-5, Conduit and Grounding Floor, El. 606, Rev. 01-47E610-70-1, Mechanical Control Diagram Reactor Building Closed Cooling Water System, Sh. 1, Rev. 22

1-45E751-2, Wiring Diagram 480V Reactor MOV BD 1A Single Line, Sh.1, Rev. 34

1-45E751-3, Wiring Diagram 480V Reactor MOV BD 1B Single Line, Sh.1, Rev. 32

1-45E751-4, Wiring Diagram 480V Reactor MOV BD 1B Single Line, Sh.1, Rev. 36

1-45E834-7, Conduit and Grounding Cable Trays Node Diagram Plan El. 565, Rev. 51-45E834-8, Conduit and Grounding Cable Trays Node Diagram Plan El. 593, Rev. 61-45E834-9, Conduit and Grounding Cable Trays Node Diagram Plan El. 621.3, Rev. 61-45N1660-3, Wiring Diagrams Unit Aux Instrument Boards Panel 9-15, Sh. 3, Rev. 1

1-45N1662-1, Wiring Diagrams Unit Aux Instrument Boards Panel 9-17, Sh. 1, Rev. 1

1-45N1662-3, Wiring Diagrams Unit Aux Instrument Boards Panel 9-17, Sh. 3, Rev. 8

1-45N1660-1, Wiring Diagrams Unit Aux Instrument Boards Panel 9-15, Sh. 2, Rev. 1

1-451749-6, Wiring Diagrams 480V Reactor MOV BD 1A Connection Diagram, Sh. 6, Rev. 3

1-45N1750-2, Wiring Diagrams 480V Reactor MOV BD 1B Connection Diagram, Sh. 2, Rev. 2

0-45N800-19,

DCA 51195-277, Rev. 000

0-45N804-19,

DCA 51194-125, Rev. 001

0-45W806-09,

DCA 51081-041, Rev. 001

1-45E712-01,

DCA 51222-010, Rev. 010

1-45E714-04,

DCA 51222-047, Rev. 001

1-45E802-33,

DCA 51195-262, Rev. 001

1-45E804-07,

DCA 51195-279, Rev. 001

1-45E804-07,

DCA 51222-560, Rev. 001

A-18Attachment1-45E804-47,

DCA 51222-295, Rev. 0011-45E804-47,

DCA 51194-047, Rev. 003

1-45E804-47,

DCA 51194-116, Rev. 001

1-45E804-47,

DCA 51194-117, Rev. 000

1-45E804-47,

DCA 51194-119, Rev. 003

1-45E804-47,

DCA 51194-121, Rev. 000

1-45N800-03,

DCA 51195-278, Rev. 000

1-45N804-07,

DCA 51177-272, Rev.001

1-45N1643-3,

DCA 51082-355, Rev. 000

1-45N1662-3,

DCA 51081-362, Rev. RB

1-45N1671-3,

DCA 51083-003, Rev. 001

1-45E1749-6,

DCA 51195-217, Rev. 003

1-45N1750-2,

DCA 51195-216, Rev. 002

1-45N1750-2,

DCA 51195-218, Rev. 002

1-730E927-8,

DCA 51081-352, Rev. 009

1-730E927-8,

DCA 51081-353, Rev. 009

1-730E927-8,

DCA 51081-354, Rev. 000

1-730E927, Primary Containment Isolation System, Sh. 14, Rev. 14

0-730E927, Primary Containment Isolation System, Sh. 15, Rev. 28

0-730E927, Primary Containment Isolation System, Sh. 12, Rev. 21Section E1.6 Special Program Activities - Cable AmpacityProcedures and Design CriteriaElectrical Design Standard

DS-E12.6.3, Auxiliary and Control Power Cable Sizing, up to 15,000Volts, Revision 10.

General Design Criteria Document

BFN-50-728, Physical Independence of Electrical Systems, Revision 13

General Design Criteria Document

BFN-50-758, Power Control and Signal Cables for use in Class 1 Structures, Revision 12. Calculations:EDQ1-999-2002-0023, Cable Ampacity Calculation for Safety Related V5 Power Cables Outsidethe Drywell Revision 15

EDQI-999-2002-0024, Cable Ampacity Calculations - V4 Cables in Trays / V4 Cables inConduit,Design Change Notices (DCN):51222, BFNP Unit 1 Restart-Electrical Lead DCN -System 074 (Reactor Building), Revision A51216, BFNP Unit 1 Recovery - Electrical Lead DCN System 57-4 (Reactor Building), Rev. A

223, BFNP Unit 1 Recovery - Electrical Lead DCN System 075 (Reactor Building), Rev. AMiscellaneous Documents:Material Issue Ticket: 58594000Material Issue Ticket:

42944000

A-19AttachmentMaterial Issue Ticket:

92464000Material Issue Ticket:

46984000

Material Issue Ticket: 97411000

Purchase Order ;

0032641, Revision 1

Purchase Order;

0031957, Revision 1.

Purchase Order :

00027543, Revision 3

Purchase Order :

00029752, dated 9/30/2003

Cable ES125-I Cable Report Cable ES173-I Cable Report Cable ES2625-II Cable Report Cable ES2673-II Cable Report Cable 1ES5404-I Cable Report Cable 1ES5412-II Cable Report Cable 1ES5408-I

Cable Report Cable 1ES5416-II Cable Report Cable 1PP9857-IA Cable Report Cable 1PP9859-IIC Cable ReportSection E1.7, Special Program Activities - Environmental Qualification (EQ) of ElectricalEquipment and Piece Parts Qualification ProgramProcedures1-EOI-1, Reactor Pressure Vessel (RPV) Control, Draft (Rev. 0) 1-EOI-2, Primary Containment Control, Draft (Rev. 0)

1-EOI-3, Secondary Containment Control, Draft (Rev. 0)

1-C-1, Alternative Level Control, Draft (Rev. 0)

1-C-2, Emergency RPV Depressurization, Draft (Rev. 0)

1-C-4, RPV Flooding, Draft (Rev. 0)

1-C-5, Level/Power Control, Draft (Rev. 0)Qualification Maintenance Data SheetsMOT-001, General Electric

Motors, Rev. 18MOV-001, AC Actuators - RH Insulation Limitorque, Rev. 22

MOV-002, AC Actuators - (Outside Drywell) Limitorque, Rev. 30

IFS-003, Flow Switches - Static-O-Ring Series 141, Rev. 1

XMTR-001, Pressure Transmitter - Rosemount Model 1153B, Rev. 16

XMTR-005, Pressure Transmitters - Rosemount Corporation, Rev. 10

XMTR-008, Weed Instrument - DTN2010 Series Pressure Transmitters, Rev. 0

ILE-001, Level Switches - Fluid Components, Rev. 13

ITE-001, RTD Assembly - Weed Instrument Co., Inc., Rev. 11

IZS-004, Namco Limit Switch Model EA740, Rev. 2

SOL-003, Solenoid Valves - NP Series - ASCO, Rev. 24

SOL-008, Soleniod Valves - Target Rock, Rev. 7

PENE-001, Electrical Penetration Assembly - Conax Corporation, Rev. 10

PENE-002, Electrical Penetration Assembly - General Electric, Rev. 9

PNL-003, AC Units - Ellis & Watts, Rev. 17

TBK-001, Terminal Blocks - General Electric, Rev. 19

A-20AttachmentXDF-001, Brown Boveri Shutdown BD RM Transformers, Rev. 8 PERs113105, Motor T-Drain Plugged With Paint on 1-MVOP-075-0009111233, Weed Transmitter Usage Problem

101799, Rosemount Pressure Transmitter Unused Electrical Connection Port

111816, No Formal QMDS Baseline Process For All Unit 1 EQ O-Ring Replacements/Torque

108690, Pressure Transmitter Cover Warped for DCN 51243

108449, Inadequate Corrective Action Implementation of PER 101799

113169, O-Ring Not Replaced as Delineated in QMDS

95080, EQ Binder Restrictions Omitted From Installation Requirements

95574, Detailed Configurations and Calculations Not Provided For Raychem Splices

94470, Nonconforming Raychem InstallationsCompleted Work Orders02-015487-033, Installed Transmitter Electronics Covers, Completed 9/22/0505-715065-000, Calibrate1-FT-23-36, 1-FM-23-36, 1-FI-23-36, 1-PXMC-23-114B, 1-FS-90-

133B, Completed 11/7/05

2-012506-000, Remove 1C Core Spray Motor, Send to Power Service Shop, Completed

9/29/06

2-012504-000, Remove 1C Core Spray Motor, Send to Power Service Shop, Completed

9/29/06

03-021141-048, Transmitter Needs To Be Replaced Because Cover Threads Are Galled

06-7242330-00, replaced the flow transmitter 1-FT-23-0036 O-rings and properly torqued the housing covers on the flow transmitter

06-724635-00, perform inspections of the MOV's in the various systems including the limit switch compartment T drains, and to remove any drain obstructions found for System 01, Main Steam System

06-724637-00, perform inspections of the MOV's in the various systems including the limit switch compartment T drains, and to remove any drain obstructions found for System 23, RHRSW

06-724646-00, perform inspections of the MOV's in the various systems including the limit switch compartment T drains, and to remove any drain obstructions found for System 73, HPCI

06-724648-00, perform inspections of the MOV's in the various systems including the limit switch compartment T drains, and to remove any drain obstructions found for System 75Piece Parts Maintenance ReviewsW84051201007W84050822009

W84051201004

W84051201005

W84051201006Other Documents ReviewedBFN-VTD-R369-0110, Rosemount Product Manual For Model 1153 Series B Alphaline

Presssure Transmitter For Nuclear Service

A-21AttachmentGeneral Design Criteria Document

BFN-50-7307, "Browns Ferry Nuclear Plant Post-Accident

Monitoring," Revision 7

Environmental Qualification Change Supplement (EQCS) No.

QMDS-ITE-001-51166, RTD

Assembly Weed Instrument Co., Inc., Rev. 0

EQCS No.

QMDS-MOT-001-51223, GE Motors, Rev. 0

EQCS No.

QMDS-XMTR-001-51199, Pressure Transmitters Rosemount Model 1153B, Rev. 0EQCS No.

QMDS-XMTR-008-51234, Presssure Transmitter DTN20110 Series - Weed

Instrument, Rev. 0 List of EQ Components That Were Field Inspected 1-MTR-075-00051-PT-064-0058B1-MTR-075-00141-PT-064-0058C

1-MVOP-075-0009

1-PT-064-0058D

1-FS-075-0021

1-PT-003-0074A

1-FT-075-00211-PT-003-0074B

1-MVOP-074-00071-TE-064-0052A

1-FS-074-00501-TE-064-0052C

1-FT-074-00501-MVOP-069-0001

1-MVOP-074-00531-FSV-043-0013

1-MVOP-074-00671-ZS-043-0013A

1-PT-068-00951-ZS-043-0013B

1-PT-068-00961-EPEN-100-0104AF

1-LT-003-00521-EPEN-100-0108A

1-LT-003-0062A1-EPEN-100-0100A

1-LT-064-0058A1-EPEN-100-0110ASaved EQ Components Reviewed For Piece Parts Qualification By Reviewing MaintenanceRecords1-FSV-031-23001-MTR-075-00051-FSV-031-23101-MTR-075-0014

1-MTR-031-23001-MTR-075-0033

1-MTR-031-23101-MTR-075-0042

1-TB-031-9556A1-LE-085-0045A

1-TB-031-9556B1-LE-085-0045B

1-TB-031-9557A1-LE-085-0045G

1-TB-031-9557B1-LE-085-0045H

1-TB-031-9557C1-EPEN-100-0104F

0-FSV-067-00531-EPEN-100-0108A

0-TB-067-86651-BUS-231-0001A

1-BUS-231-0001BCalculationsND-Q0075-870022, Master Components Electrical List (MCEL) System 075, Rev. 13ND-Q0075-870022, MCEL System 074, Rev. 13

ND-Q0064-870013, MCEL System 064, Rev. 19

2AttachmentSection E1.8 Special Program Activities - Instrument Sensing LinesSpecifications & ProceduresTVA Engineering Specification N1E-003, Instrument and Instrument Line Installation andInspection, Rev. 1

MAI-4.2A,

TVA-BFNP Piping/Tubing Supports, Rev. 33

MAI-4.4A,

TVA-BFNP Instrument Line Installation, Rev. 16DrawingsDrawing number 0-47B435-1 through -21, Mechanical General Notes, Pipe Supports Drawing numbers 1-47E600-2602 through -2604, and -2611, Mechanical Instrumentation and Controls, Primary Containment System Sensing Line Isometrics Drawing numbers 1-47E600-778, and -2660, Mechanical Instrumentation and Controls, Primary Containment System Sensing Line Isometrics Drawing number 1-47E600-2614, Mechanical Instruments and Controls, Containment Inerting, Sensing Line Isometrics Drawing numbers 1-47E600-2577, -2578, and -2586 through -2589, Mechanical Instrumentation and Controls, RHR Sensing Line Isometrics Drawing numbers 1-47E600-2590, -2591, and -2599 through -2601, Mechanical Instrumentation and Controls, RHR Sensing Line Isometrics Drawing numbers 1-47E600-2575,

Mechanical Instrumentation and Controls, RCIC Sensing Line Drawing number 1-47E600-2571, Mechanical Instrumentation and Controls, HPCI Sensing Line Drawing numbers 1-47E600-2567, -2568, and -2569, Mechanical Instrumentation and Controls,

HPCI Sensing LineProblem Evaluation Reports (PER)111624, System 74, Incorrect Slope for Sensing Line associated with Instrument 1-PI-074-0014112015, RHR Instrument Line Support Deficiencies

2017, RHR Instrument Lines - Drawing discrepancies

113175, Sections of RVLIS Instrument Line Requires Slope Adjustment

113480, Instrument Lines from Penetrations X-26A & X-26B have Incorrect Slope

113850, Discrepancies Identified During Closeout of Instrument Line WO# 03-004722

114318, System 64 Instrument Line Potential Slope Discrepancies

114319, Damaged Instrument Line Tubing Associated with BFR-1-PS-067

and

BFR-1-VTV-067-0051

114366, Damaged Section of Instrument Line Connecting

BFR-1-PS-073-0029 and -0029-1 with Inadequate Slope and Root Valve

BFR-1-CKV-032-3749 and

BFR-1-CKV-032-3750

114372, System 64, Discrepancies in Instrument Sensing Line Slope

115509, System 03 Slope Discrepancies Various Locations

115510, System 68 Slope Discrepancies Various Locations

115514, System 85 Slope Discrepancies Various Locations

115516, Slope Discrepancies on Instrument Lines to BFR-1-PDT-085-0017(L),

BFR-1-PDT-085-0018(L), BFR-1-PDT-085-0019

115429, Improperly Installed T-Drains

A-23Miscellaneous DocumentsCalculation number EDQ199920030004, Rev. 0, Instrument sensing Lines - BFN Slope, ValveStem Orientation, Separation

DCN 51201, Modifications to Instrument Sensing Lines, Containment Inerting System, and Exception Number

EX-N1E-003-99

DCN 51236, Modifications to Instrument Line Slope, System 71, Reactor Core Isolation Cooling

DCN 51237, Modifications to Instrument Line Slope, System 73, High Pressure Coolant Injection, and Exception Numbers

EX-NE1E-003-82, Rev. 2,

EX-NE1E-003-83, Rev. 1, and

EX-NE1E-003-84, Rev. 2

DCN 51243, Modifications to Instrument Line Slope, System 64, Containment Isolation, and Exception Numbers

EX-NE1E-003-88, Rev. 1 and

EX-NE1E-003-89, Rev. 2

DCN 51245, Modifications to Torus Water Level Instrument Sensing Lines

DCN 51199, Modifications to Instrument Sensing Lines, RHR System, and Exception Numbers

EX-N1E-003-70,

EX-N1E-003-71,

EX-N1E-003-75,

EX-N1E-003-76, EX-N1E-003-79,

EX-N1E-003-85,

EX-N1E-003-90,

EX-N1E-003-91,

EX-N1E-003-92,

EX-N1E-003-95, and

EX-N1E-003-97Section E1.9 Special Program Activities - Containment CoatingsProcedures and Design CriteriaTVA General Engineering Specification G-55, Technical and Programmatic Requirements forthe Protective Coating Program for TVA Nuclear Plants

0-SI-4.7.A.2.K, Primary Containment Drywell Surface Visual Inspection, Rev. 12

0-TI-417, Inspection of Service Level I, II, III Protective Coatings, Rev. 5

WI-BFN-1-GEN-01, General Requirements for Walkdowns, Rev. 4

WI-BFN-1-MEB-03, BFN Unit 1 Primary Containment Coatings Inspection Plan, Rev. 1Problem Evaluation Reports (PER)96670, Recordable Indications in Drywell Vessel Base Metal112179, Defective Coatings Identified on Exterior Surface of Torus Bay #9

113545, Water Leakage at Azimuth 292 Shows Evidence of Corrosion

115972, Number of Locations Reduced in 1-TI-521 Inspection ProgramMiscellaneous DocumentsCalculation number CDQ0303970088, Rev. 6, Evaluation of Reduction in Thickness of theDrywell Liner Plate Due to Minor Surface Corrosion

2006 Drywell Coating Inspection Records - Summary of Components with Unqualified Coating -

area and average dry film thickness of existing coating Notification of Indication Forms, numbers U1C6R-027, U1C6R-028, U1C6R-032, and

U1C6R-033

Work Order 02-005150-000, Drywell Vessel Adhesion Test Results Work Order 03-011002-003, Repair or Replace Moisture Barrier

A-24AttachmentSection E1.11 Special Program Activities - Large Bore Piping and Supports and LongTerm Torus IntegrityProcedures and Design CriteriaProcedure No.,

WI-BFN-0-CEB-01, Walkdown Instruction for Piping and Pipe SupportsDesign Criteria

BFN-50-C-7100, Design of Civil Structures, Attachment A - General Design Criteria for the Torus Integrity Long Term Program, Rev. 16

Design Criteria

BFN-50-C-7107, Design of Class I Seismic Pipe and Tubing Supports, Rev. 7

Design Criteria

BFN-50-C-7103, Structural Analysis and Qualification of Mechanical and Electrical Systems (Piping and Instrument Tubing), Attachment A, Rigorous Piping Analysis and

E, Analysis of Torus Attached Piping (Long Term Torus Integrity Program)Other DocumentsPipe Support Drawing No. 1-47B401-4, Sheets 1 & 2, Rev. 003 & 001Pipe Support Drawing No. 1-47B401-5, Sheets 1 & 2, Rev. 003 & 002

Pipe Support Drawing No. 1-47B401-15, Sheets 1 & 2, Rev. 003 & 002

Pipe Support Drawing No. 1-47B401-20, Sheet 1, Rev. 001

Pipe Support Drawing No. 1-47B401-50, Sheet 1, Rev. 002

Pipe Support Drawing No. 1-47B452-3268, Sheet 1, Rev. 001

Pipe Support Drawing No. 1-47B452-3269, Sheet 1, Rev. 001

Pipe Support Drawing No. 1-47B452-3290, Sheets 1 & 2, Rev. 001

Pipe Support Drawing No. 1-47B452-3291, Sheets 1 & 2, Rev. 001

Pipe Support Drawing No. 1-47B452-3295, Sheet 1, Rev. 002

DCN 51341, Reactor Core Isolation Cooling (RCIC) System Large Bore for Long Term Torus Integrity Program for Bulletins 70-02/79-14

DCN 51343, Reactor Core Isolation Cooling (RCIC), High Pressure Cooling Injection (HPCI), Residual Heat Removal (RHR), and Core Spray (CS) Systems Large Bore for Long Term Torus Integrity Program for Bulletins 70-02/79-14

Work Orders

(WOs) 03-005172 for

DCN 51341 and 03-008332 for DCN 51343

PERs

112103,

111334,

113095,

113012,

113005, and 113011Section E1.12: Readiness for Maintenance RuleProcedures1-TI-270, Fuel Load and Restart Prerequisite Checklists, Rev 00-TI-346, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting -

0CFR50.65, Rev 27

SPP-6.6, Maintenance Rule Performance Indicator Monitoring, Trending and Reporting -

10CFR50.65, Rev 8Corrective Action Documents63777, BFNR Maintenance Rule plan88555, EPIX Discrepancies from MR Self-Assessment BFN-ENG-05-003

85673, Missing MR Unavailability/Reliability Data

88553, MR Self-Assessment

BFN-03-005 MR reporting criteria discrepancies

A-25Attachment89036, RHR NEI/NRC Performance Indicator96650, MR Unavailability Flagging

100775, MR

SPP-6.6 Deficiencies

106895, MR Implementation for U1Other DocumentsND-N0999-970002, Determination of Risk-Significant Systems, Rev 8ND-N0999-970003, PSA Evaluation of Maintenance Rule (10CFR50.65) Performance Criteria System Return to Service - Open Item Punchlist, various Brown's Ferry Nuclear Plant, Maintenance Rule 5th Periodic Report, April 2004 to March 2006BFN-ENG-05-003, Maintenance Rule Self-Assessment Report Letter from USNRC to Mr. J.A. Scalice (CNO TVA), SUBJ: ISSUANCE OF TEMPORARY

PARTIAL EXEMPTION FROM 10

CFR 50.65; BROWN'S FERRY NUCLEAR PLANT, UNIT 1

(TAC NO. MA5033) Section E1.13: Station BlackoutCalculationsBWROG Emergency Procedure and Severe Accident Guidelines, Appendix C, CalculationsDRF-A22-00125-56-01, TVA BFU 2 and 3 Extended Power Uprate for SBO (Task T0903), Rev 0MD-N0248-920016, 250V Battery Electrolyte Temperature for SBO and Appendix R, Rev. 0

MD-N0999-980114, Station Blackout Evaluation, Rev. 3

MD-Q00829-00091, Diesel Generator Temperature Rise Evaluation, Rev 2

MD-Q00829-00102, Diesel Generator Temperature Rise Evaluation at Partial Load, Rev 1

MD-Q0999-890014, Operability of Station Blackout Response Equipment for BFN, Rev. 5

MD-Q0999-920053, Station Blackout - Multi-Unit HVAC and DG Availability Analysis, Rev. 8

NEDO-31331, BWR Owner's Group Emergency Procedure Guidelines, Rev. 4

ND-N0999-890021, Station Blackout Equipment List, Rev. 5

ND-N2999-910022, HPCI and RCIC Statiion Blackout Qualification, Rev. 3

NDQ1-999-2003-008, Reactor Building Temperature Response During SBO, Rev. 0Design Changes / ModificationsW17725B, Remove Non-1E Loads form Unit BatteryW17726B, Remove Non-1E Loads from Unit Battery

W17727C, Remove Non-1E Loads from Unit Battery

51085A, Replace Unit Preferred MMG Set with UPS SystemDrawingsM-1-47E610-64-1, Mechanical Control Diagram, Primary Containment System, Rev 67UFSAR Figure 10.10-1a, Emergency Equipment Cooling Water Flow Diagram

PIP-02-03, Electrical Distribution System, Unit 0, Browns Ferry Nuclear Plant, Rev. 11/13/06

A-26AttachmentProceduresAOI-57-1A, Loss of Offsite Power (161 and 500 KV)/Station Blackout, Rev. 64EOIPM Section 2-VI-F, Worksheet 5, Heat Capacity Temperature Limit, Rev 8

EOIPM Section 2-VI-H, Worksheet 8, Pressure Suppression Pressure, Rev 8PERs114967, SBO calculation did not adequately consider potential loss of all EECW114913, LOOP/SBO procedure did not adequately address potential loss of all EECW

114790, Errors in EDG reliability calculation

114915, Error in EOIPM calculation

114942, Drawing errors

114999, 50.59 for PSP and HCTL curves

115001, 50.59 for PSP and HCTL curvesOther50.59 Screening Review for EOIPM Rev 25UFSAR Section 8.5, Standby AC Power Supply and Distribution

UFSAR Section 8.10, Station Blackout

UFSAR Section 10.10, Emergency Equipment Cooling Water SystemSection E8.1: Generic Letter (GL) 92-04 and IE Bulletin (IEB) 93-03, Resolution of IssuesRelated to Reactor Vessel Water Level Instruments in BWRsProcedures:NEI 96-07, Guidelines for 10

CFR 50.59 Implementation, Rev. 1Special Instrument Instruction,

SII-1-F-085-0763, Reactor Water Level Reference Leg Backfill System, Rev. 00

Mechanical Section Instruction,

MSI-0-000-CKV001, Maintaining Check Valves, Rev. 25

Special Instrument Instruction,

SII-0-XX-00-130, Backfilling of Instrument Sense Lines, Rev. 11A3-SIMI-85B, BFN Scaling and Setpoint Document, CRD Backfill Line Flow Indicator Calculations:EDQ0003940050, RVLIS Continuous Backfill Accuracy Justification, Rev. 1 Miscellaneous Documents:UFSAR Chapter 7.10, Feedwater Control System UFSAR Chapter 7.8, Reactor Vessel Instrumentation

DCN 51163A, 50.59 screening review, Modify RVLIS reference and sensing lines

DCN 51231A, 50.59 screening review, Modify RVLIS instrumentation and controls

DCN 51231A, 50.59 screening review, Modify CRD instrumentation and controls

A-27AttachmentSection E8.4:

GL 89-10, Safety Related Motor Operated Valve Testing and SurveillanceDesign Specifications:G-50, Rev 6, Torque and Limit Switch Settings for Motor-Operated ValvesDS-M18.2.21, Rev 15, Motor Operated Valve Thrust and Torque Calculations

DS-M18.2.22, Rev 2, MOV Design Basis Review MethodologyCalculations:MDQ0999980001, Rev. 3, MOV Calculation Input ParametersMDQ0999000015, Rev. 3, MOV Calculation Input Parameters Mini-Calculation

MDQ0999910034, Rev. 14, NRC Generic Letter 89-10- Motor Operated Valve Evaluation

MDQ0999980137, Rev. 5, Evaluation of Stroke Times of

GL 89-10 MOVs Equipped with DC

Motors

MDQ1-9999-2002-0114, Evaluation of

GL 89-10 MOVs Equipped with DC Motors

MDQ1-071-2002-0095, MOV 1-FCV-071-0008, Operator Requirements and Capabilities

MDQ1-073-2002-0104, MOV 1-FCV-073-0044, Operator Requirements and Capabilities

MDQ1-074-2002-0077, Rev. 2, MOV 1-FCV-074-0060, MOV 1-FCV-074-0061,

MOV1-FCV-074-0074 & MOV 1FCV-074-0075, Operator Requirements and Capabilities.

MDQ1-071-2002-0106, Rev. 2, MOV 1FCV-071-0039, Operator Requirements and Capabilities

MDQ1-074-2002-0103, Rev. 1, MOV 1-FCV-074-0047, Operator Requirements and Capabilities

MDQ1-073-2002-0089, Rev. 1, MOV 1-FCV-073-0016, Operator Requirements and Capabilities

MDQ1-074-2002-0078, Rev. 1, MOV 1-FCV-074-0059 & MOV 1-FCV-074-0073, Operator Requirements and CapabilitiesProcedures:ECI-0-000-MOV007, Rev. 14, (High-Speed) Limitorque Motor Operated Valves ElectricalAdjustments

EII-0-000-MOV002, Rev. 8, Electrical Information Instruction for MOVATS Signature AnalysisSystem

ECI-0-000-MOV002, Rev. 19, (Non-High Speed) Limitorque Motor Operated Valves Electrical Adjustments

MMDP-5, Rev 6, MOV Program Draft

MMDP-5, Rev 7, MOV Program

NEDP-2, Rev 11, Design Calculation Process Control

NEDP-12, Rev 7, System and Component Health, Equipment Failure TrendingDrawings:Sample of 1-47A370 series

Miscellaneous

Documents:Sample MOV Static and Dynamic Test Packages for 1-FCV-074-0007, 1-FCV-074-0059TVA Letters: 12-21-1990,11-18-1996, 03-17-1997, 04-28-1998, 05-05-2004, 12-19-2005,

09-22-2006

A-28AttachmentSection E8.5:

GL 96-01, Testing of Safety-Related Logic CircuitsProcedures:0-SR-3.8.1.8(I), 480V Load Shedding Logic System Div I Functional Test1-SR-3.3.1.1.12, RPS Mode Switch in Shutdown Scram and Logic System Functional Test

1-SR-3.3.1.1.4 (12A), RPS Channel A1/A2 Test Switch Functional Test

1-SR-3.3.1.1.8 (11), RPS Manual Scram Functional Test

1-SR-3.3.1.1.8(5), MSIV Closure - RPS Trip Functional Test

1-SR-3.3.5.1.3 (ADS A/RHR), RHR System Pump Discharge Pressure ADS Press Cal

1-SR-3.3.5.1.6(A I), Functional Testing of RHR Loop I Auto Initiation Logic

1-SR-3.3.5.1.6(BII), Functional Testing of RHR Loop II Pump and Min Flow Logic

1-SR-3.3.6.1.6(SDC), Functional Testing of RHR Shutdown Cooling Suction Valve Logic

1-SR-3.5.1.9(RHR I), Loop I RHR Simulated Automatic Actuation Test Miscellaneous Documents:NRC Inspection Report 50-259, 260, 296/ 98-03NRC Inspection Report 50-259, 260, 296/ 98-05

NRC Inspection Report 50-259, 260, 296/ 98-07

EDM, Determination of Risk-Significant Systems and Components for 10CFR50.65, Rev.

0

Reg Guide 1.118, Periodic Testing of Electric Power and Protection Systems, Rev.

3

Reg Guide 1.32, Criteria for Safety-Related Electric Power Systems for Nuclear PlantsSection E8.8: Inspector Followup Item (IFI) 50-259/95-55-01, Review of Licensee FinalSafety Analysis Report (FSAR) Commitments for Continuous Air Monitors (CAMs)Associated with Units 1 and 3Records reviewed:IRM-090-0050, Unit 0, SII--XX--3014, Troubleshooting and Configuration Control ofInstrumentation, Revision (Rev.) 0017, SCI/CCI Data Package Cover Sheet, Attachment 7, Dated 10/31/06

IRM-090-0051, Unit 0, SII--XX--3014, Troubleshooting and Configuration Control of Instrumentation, Rev. 0017, SCI/CCI Data Package Cover Sheet, Attachment 7, Dated 11/15/06

IRM-090-0054, Unit 0, SII--XX--3014, Troubleshooting and Configuration Control of Instrumentation, Rev. 0017, SCI/CCI Data Package Cover Sheet, Attachment 7, Dated 10/24/06

IRM-090-0055, Unit 0, SII--XX--3014, Troubleshooting and Configuration Control of Instrumentation, Rev. 0017, SCI/CCI Data Package Cover Sheet, Attachment 7, Dated 10/30/06

IRM-090-0056, Unit 0, SII--XX--3014, Troubleshooting and Configuration Control of Instrumentation, Rev. 0017, SCI/CCI Data Package Cover Sheet, Attachment 7, Dated 11/07/06

IRM-090-0057, Unit 0, SII--XX--3014, Troubleshooting and Configuration Control of Instrumentation, Rev. 0017, SCI/CCI Data Package Cover Sheet, Attachment 7, Dated 10/30/06

IRM-090-0058, Unit 0, SII--XX--3014, Troubleshooting and Configuration Control of Instrumentation, Rev. 0017, SCI/CCI Data Package Cover Sheet, Attachment 7, Dated 10/31/06

A-29AttachmentSection E8.15:

URI 50-259/2006-08-02, Impact of Duct tape on Instrument TubingRecords reviewed:Central Laboratories Services Technical Report AG56961G29 Part B - Standard Material Specifications,

PF-1054, Revision 6

G29B - External Surface Cleanness of Austenitic Stainless Steel Piping and Components,

PS4.M.4.1, Revision 9

G29BS01 - Process Specification for Material Fabrication and Handling Requirements for Austenitic Stainless Steel, PS 4.M.1.1, Revision 23

MSI-0-000-PRO001, Cleanliness of Fluid Systems, Revision 21

TI-92, Determination of Chloride and/or Flouride Contamination Using Sponge Swipes, Rev 10

0-TI-397, Performance of Maintenance Inspections and Verifications, Revision 6ASection M1:

Conduct of MaintenanceProcedures and StandardsMCI-0-085-HCU001, Maintenance of CRD Hydraulic Control Units, Rev 57 and 62 GE Vendor Manual,

GEK-9582C, Operation and Maintenance Instructions for Hydraulic Control Units Work Orders06-724834-000, repair of Hydraulic Control Unit 34-27 scram outlet valve air leak 06-725548-000 which documented a problem with

HCU 34-27 scram inlet and outlet valve diaphragms being invertedPERs70219, maintenance on scram inlet and outlet valves with the diaphragms installed inverted

117046, maintenance on scram inlet and outlet valves with the diaphragms installed inverted

115040, scram valve diaphragm installed with concave side facing down

114748, Hydraulic Control Unit 34-27 scram outlet valve air leakMiscellaneous DocumentsGE Service Information Letter (SIL) 457, "Hammel-Dahl Scram Valve Diaphragm Leakage," withSupplement 1Section F1.1:

Restart Special Program - Fire Protection ImprovementsProcedures and StandardsOPDP-1, Conduct of Operations, Rev. 00070-SSI-001; Safe Shutdown Instructions, Rev. 0

0-SSI-1-1; Unit 1 Reactor Building Fire

EL 519 through 565West of Column Line R4, Rev. 0

0-SSI-1-5; Unit 1 Reactor Building FireEL 621 and 639North of Column R, Rev. 0

0-SSI-3-1; Unit 3 Reactor Building Fire

EL 519 through 565, West of R18,Eqpt Hatch Between

A-30Attachment Col R15 and R17, T and U Line at

EL 593 & 621, 639 South of R Line, Rev. 00-SSI-3-3; Unit 3 Reactor Building Fire

EL 593 and RHR Heat Exchanger Rooms,

Rev. 0

0-SSI-16; Control Building Fire

EL 593 through 617, Rev. 0

0-SSI-25I; Turbine Building, Cable Tunnel, Intake Pumping Station and Radwaste

Building, Rev. 0

0-SSI-25II; Turbine Building, Cable Tunnel, Intake Pumping Station and Radwaste Building, Rev. 0PERs104575, BFN Fire Protection written to track the NRC URI110538, 4KV SHDN Bd A may not be Available in Fire Area 8

110612, 2-FCV-74-53, and 67

110657, Nextel Cell Phone Coverage

110658, Validation of SSI's Do Not Consider All Parameters in 711111.05T

118363,

DCN 51092 Stage 5 RTO'd without performing field work

118435, Credited Appendix R communications not available for fire area 25

104418, Significance Determination Process Evaluation of Fire Scenarios for

Appendix R

118616, Appendix R Manual Actions

118239, Drawing Discrepancies Regarding Emergency Light Aiming

118291, Discrepancy in Appendix R Emergency Light PMTI-51092-STG03

118293, Typo on Cover Sheet of

PMTI-51229-STG06Miscellaneous Documents0-SR-3.3.3.2.1(23) Backup Control Panel Testing, Rev. 80-SR-3.3.3.2.1(24) Backup Control Panel Testing, Rev. 0

0-SR-3.3.3.2.1(26) Backup Control Panel Testing, Rev. 3

0-SR-3.3.3.2.1(43) Backup Control Panel Testing, Rev. 0

0-SR-3.3.3.2.1(67) Backup Control Panel Testing, Rev. 6

0-SR-3.3.3.2.1(69) Backup Control Panel Testing, Rev. 0

1-SR-3.3.3.2.3(1A) Backup Control System Reactor Water Level Indication Calibration, Rev. 0

1-SR-3.3.3.2.3(03) Backup Control System Suppression Pool Temperature Indication Calibration, Rev. 0

1-SR-3.3.3.2.3(06) Backup Control System RHR System II Total Flow Indication Calibration, Rev. 4

LSWDP-BFN-0-ELEC-385, Walkdown of Unit 0 Appendix R Safe Shutdown Instructions, Fire Area 1-1, Rev. 0

LSWDP-BFN-0-ELEC-389, Walkdown of Unit 0 Appendix R Safe Shutdown Instructions, Fire Area 1-5, Rev. 0

LSWDP-BFN-0-ELEC-397, Walkdown of Unit 0 Appendix R Safe Shutdown Instructions, Fire Area 3-1, Rev. 0

LSWDP-BFN-0-ELEC-399, Walkdown of Unit 0 Appendix R Safe Shutdown Instructions, Fire Area 3-3, Rev. 0

LSWDP-BFN-0-ELEC-422, Walkdown of Unit 0 Appendix R Safe Shutdown Instructions, Fire Area 25-I

LSWDP-BFN-0-ELEC-423, Walkdown of Unit 0 Appendix R Safe Shutdown Instructions, Fire Area 25-II

DCN Test Scoping Document for In-Plant VHF Radio System F2 and F4 for Appendix R

A-31Attachment Communications

PMT-DCN 51092-3DCN 68584 A, Add 3 Hour Battery UPS to F2 Radio Repeater and Re-Route Communications Cable

PIC 68588 A Revise DCAs Based on Appendix R Manual Action Calculation and

Emergency Lighting Calculation Calculation

EDN 0244890050 Appendix R Analysis For Intraplant Communication

System Rev. 8

Listing of Manual Actions requiring SCBAs Calculation EDQ09999-2003-0048, Rev. 8, Unit 1,2,and 3 Appendix R Manual Action Requirements

DCN 51229,

System 247 - Emergency Lighting System Modifications to Support Appendix R, Rev. A

DCN 51229-4, Stages 3A and 3B, Appendix R Emergency Lights, dated 1/18/2007

Illuminating Engineering Society Handbook, Application Volume Figure 2-26, 1987 Edition