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| number = ML080440179
| number = ML080440179
| issue date = 01/31/2008
| issue date = 01/31/2008
| title = Safety Evaluation Report, Related to the License Renewal of Vermont Yankee Nuclear Power Station.
| title = Safety Evaluation Report, Related to the License Renewal of Vermont Yankee Nuclear Power Station
| author name = Rowley J G
| author name = Rowley J
| author affiliation = NRC/NRR/ADRO/DLR
| author affiliation = NRC/NRR/ADRO/DLR
| addressee name =  
| addressee name =  
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{{#Wiki_filter:Safety Evaluation Report Related to the License Renewal of Vermont Yankee Nuclear Power StationDocket No. 50-271Entergy Nuclear Operations, Inc.U.S. Nuclear Regulatory CommissionOffice of Nuclear Reactor RegulationJanuary 2008 THIS PAGE INTENTIONALLY LEFT BLANK.
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iiiABSTRACTThis safety evaluation report (SER) documents the technical review of the Vermont YankeeNuclear Power Station (VYNPS) license renewal application (LRA) by the United States (US)
Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated January 25, 2006, Entergy Nuclear Operations, Inc. (ENO or the applicant) submitted the LRA in accordance with Title 10, Part 54, of the Code of Federal Regulations, "Requirements for Renewal of OperatingLicenses for Nuclear Power Plants." ENO requests renewal of the VYNPS operating license (Facility Operating License Number DPR-28) for a period of 20 years beyond the current expiration at midnight March 21, 2012.VYNPS is located approximately five miles south of Brattleboro, Vermont. The NRC issued theVYNPS construction permit on December 11, 1967, and the operating license on February 28, 1973. VYNPS is of a Mark 1 Boiling Water Reactor (BWR) design. General Electric supplied the nuclear steam supply system and Ebasco originally designed and constructed the plant.
The VYNPS licensed power output is 1912 megawatt thermal with a gross electrical output of approximately 650 megawatt electric.This SER presents the status of the staff's review of information submitted through OctoberJanuary XX, 2007 2008, the cutoff date for consideration in the SER. The staff identified sixconfirmatory items which were resolved before the staff made a final determination on the LRA.
SER Section 1.6 summarizes these items and their resolution. Section 6.0 provides the staff's final conclusion on the review of the VYNPS LRA.
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vTABLE OF CONTENTSAbstract..................................................................iiiTable of Contents...........................................................vAbbreviations.......................................................xiiiIntroduction and General Discussion...........................................1-11.1  Introduction.....................................................1-11.2  License Renewal Background......................................1-21.2.1  Safety Review...........................................1-3 1.2.2  Environmental Review.....................................1-41.3  Principal Review Matters..........................................1-5 1.4  Interim Staff Guidance............................................1-61.5  Summary of Open Items...........................................1-71.6  Summary of Confirmatory Items.....................................1-7 1.7  Summary of Proposed License Conditions.............................1-9Structures and Components Subject to Aging Management Review...................2-12.1  Scoping and Screening Methodology.................................2-12.1.1  Introduction.............................................2-12.1.2  Summary of Technical Information in the Application..............2-1 2.1.3  Scoping and Screening Program Review.......................2-22.1.3.1  Implementation Procedures and Documentation Sources forScoping and Screening..............................2-32.1.3.2  Quality Controls Applied to LRA Development............2-6 2.1.3.3  Training.........................................2-6 2.1.3.4  Conclusion of Scoping and Screening Program Review ..........................................2-72.1.4  Plant Systems, Structures, and Components Scoping Methodology..2-72.1.4.1  Application of the Scoping Criteria in 10 CFR 54.4(a)(1)....2-8 2.1.4.2  Application of the Scoping Criteria in 10 CFR 54.4(a)(2) ..2-12 2.1.4.3  Application of the Scoping Criteria in 10 CFR 54.4(a)(3) ..2-18 2.1.4.4  Plant-Level Scoping of Systems and Structures.........2-212.1.4.5  Mechanical Component Scoping.....................2-242.1.4.6  Structural Component Scoping......................2-272.1.4.7  Electrical Component Scoping.......................2-282.1.4.8  Conclusion for Scoping Methodology..................2-292.1.5  Screening Methodology...................................2-292.1.5.1  General Screening Methodology.....................2-292.1.5.2  Mechanical Component Screening...................2-302.1.5.3  Structural Component Screening.....................2-322.1.5.4  Electrical Component Screening.....................2-332.1.5.5  Conclusion for Screening Methodology................2-352.1.6  Summary of Evaluation Findings............................2-352.2  Plant-Level Scoping Results.......................................2-36 vi2.2.1  Introduction............................................2-362.2.2  Summary of Technical Information in the Application.............2-36 2.2.3  Staff Evaluation.........................................2-36 2.2.4  Conclusion.............................................2-382.3  Scoping and Screening Results: Mechanical Systems...................2-382.3.1  Reactor Coolant System..................................2-402.3.1.1  Reactor Vessel..................................2-43 2.3.1.2  Reactor Vessel Internals...........................2-45 2.3.1.3  Reactor Coolant Pressure Boundary..................2-462.3.2  Engineered Safety Features...............................2-482.3.2.1  Residual Heat Removal............................2-482.3.2.2  Core Spray.....................................2-51 2.3.2.3  Automatic Depressurization.........................2-52 2.3.2.4  High Pressure Coolant Injection.....................2-53 2.3.2.5  Reactor Core Isolation Cooling......................2-55 2.3.2.6  Standby Gas Treatment...........................2-562.3.2.7  Primary Containment Penetrations...................2-582.3.3  Auxiliary Systems........................................2-592.3.3.1  Standby Liquid Control............................2-592.3.3.2  Service Water...................................2-61 2.3.3.3  Reactor Building Closed Cooling Water................2-67 2.3.3.4  Emergency Diesel Generator.......................2-692.3.3.5  Fuel Pool Cooling................................2-70 2.3.3.6  Fuel Oil........................................2-73 2.3.3.7  Instrument Air...................................2-75 2.3.3.8  Fire Protection-Water.............................2-77 2.3.3.9  Fire Protection-Carbon Dioxide......................2-892.3.3.10  Heating, Ventilation, and Air Conditioning.............2-942.3.3.11  Primary Containment Atmosphere Control / ContainmentAtmosphere Dilution...............................2-962.3.3.12  John Deere Diesel..............................2-1012.3.3.13  Miscellaneous Systems In-scope as required by 10 CFR54.4(a)(2)......................................2-1032.3.3.13A Augmented Off-gas............................2-103 2.3.3.13B Sampling....................................2-105 2.3.3.13C Condensate Demineralizer.......................2-1062.3.3.13D RWCU Filter Demineralizer......................2-107 2.3.3.13E Circulating Water..............................2-108 2.3.3.13F Demineralized Water...........................2-110 2.3.3.13G Feedwater...................................2-1122.3.3.13H MG Lube Oil..................................2-1132.3.3.13I Neutron Monitoring.............................2-114 2.3.3.13J Potable Water.................................2-115 2.3.3.13K Radwaste, Liquid and Solid......................2-1162.3.3.13L Equipment Retired in Place......................2-1172.3.3.13M Reactor Water Clean-Up........................2-1182.3.3.13N Stator Cooling ................................2-121 2.3.3.13O HD & HV Instruments..........................2-122 vii2.3.3.13P Air Evacuation ................................2-1232.3.3.13Q Building (Drainage System Components) ...........2-1242.3.3.13R Circulating Water Priming .......................2-124 2.3.3.13S Extraction Steam ..............................2-125 2.3.3.13T Heater Drain .................................2-126 2.3.3.13U Heater Vent ..................................2-127 2.3.3.13V Make-up Demineralizer.........................2-128 2.3.3.13W Seal Oil.....................................2-129 2.3.3.13X Turbine Building Closed Cooling Water .............2-130 2.3.3.13Y Main Turbine Generator ........................2-1312.3.3.13Z Turbine Lube Oil...............................2-1322.3.3.13AA Hydrogen Water Chemistry.....................2-1332.3.4  Steam and Power Conversion Systems......................2-1352.3.4.1  Auxiliary Steam.................................2-1352.3.4.2  Condensate....................................2-1362.3.4.3  Main Steam....................................2-138 2.3.4.4  101 (Main Steam, Extraction Steam, and Auxiliary SteamInstruments)....................................2-1392.4  Scoping and Screening Results: Structures..........................2-1402.4.1  Primary Containment....................................2-1412.4.1.1  Summary of Technical Information in the Application....2-141 2.4.1.2  Staff Evaluation.................................2-142 2.4.1.3  Conclusion.....................................2-1422.4.2  Reactor Building........................................2-1432.4.2.1  Summary of Technical Information in the Application....2-143 2.4.2.2  Staff Evaluation.................................2-144 2.4.2.3  Conclusion.....................................2-1442.4.3  Intake Structure........................................2-1442.4.3.1  Summary of Technical Information in the Application....2-144 2.4.3.2  Staff Evaluation.................................2-145 2.4.3.3  Conclusion.....................................2-1472.4.4  Process Facilities.......................................2-1472.4.4.1  Summary of Technical Information in the Application....2-147 2.4.4.2  Staff Evaluation.................................2-148 2.4.4.3  Conclusion.....................................2-1502.4.5  Yard Structures........................................2-1502.4.5.1  Summary of Technical Information in the Application....2-150 2.4.5.2  Staff Evaluation.................................2-152 2.4.5.3  Conclusion.....................................2-1522.4.6  Bulk Commodities......................................2-1522.4.6.1  Summary of Technical Information in the Application....2-152 2.4.6.2  Staff Evaluation.................................2-153 2.4.6.3  Conclusion.....................................2-1542.5  Scoping and Screening Results: Electrical and Instrumentation and ControlSystems...................................................2-154 2.5.1  Summary of Technical Information in the Application............2-155 2.5.2  Staff Evaluation........................................2-156 2.5.3  Conclusion............................................2-159 viii2.6  Conclusion for Scoping and Screening..............................2-160Aging Management Review Results...........................................3-13.0  Applicant's Use of the Generic Aging Lessons Learned Report.............3-13.0.1  Format of the License Renewal Application.....................3-23.0.1.1  Overview of Table 1s...............................3-3 3.0.1.2  Overview of Table 2s...............................3-33.0.2  Staff's Review Process....................................3-43.0.2.1  Review of AMPs..................................3-5 3.0.2.2  Review of AMR Results.............................3-6 3.0.2.3  UFSAR Supplement...............................3-63.0.2.4  Documentation and Documents Reviewed..............3-63.0.3  Aging Management Programs...............................3-73.0.3.1  AMPs Consistent with the GALL Report...............3-103.0.3.2  AMPs Consistent with the GALL Report with Exceptions and/orEnhancements...................................3-413.0.3.3  AMPs Not Consistent with or Not Addressed in the GALL Report..............................................3-1103.0.4  Quality Assurance Program Attributes Integral to Aging ManagementPrograms............................................3-145 3.0.4.1  Summary of Technical Information in the Application....3-146 3.0.4.2  Staff Evaluation.................................3-146 3.0.4.3  Conclusion.....................................3-1483.1  Aging Management of Reactor Vessel, Reactor Vessel Internals, and ReactorCoolant System.............................................3-148 3.1.1  Summary of Technical Information in the Application............3-148 3.1.2  Staff Evaluation........................................3-1493.1.2.1  AMR Results Consistent with the GALL Report.........3-1683.1.2.2  AMR Results Consistent with the GALL Report for Which FurtherEvaluation is Recommended.......................3-1803.1.2.3  AMR Results Not Consistent with or Not Addressed in the GALLReport.........................................3-1933.1.3  Conclusion............................................3-1993.2  Aging Management of Engineered Safety Features Systems.............3-1993.2.1  Summary of Technical Information in the Application............3-200 3.2.2  Staff Evaluation........................................3-2003.2.2.1  AMR Results Consistent with the GALL Report.........3-2103.2.2.2  AMR Results Consistent with the GALL Report for Which FurtherEvaluation is Recommended.......................3-2203.2.2.3  AMR Results Not Consistent with or Not Addressed in the GALLReport.........................................3-2313.2.3  Conclusion............................................3-2413.3  Aging Management of Auxiliary Systems............................3-2413.3.1  Summary of Technical Information in the Application............3-241 3.3.2  Staff Evaluation........................................3-2423.3.2.1  AMR Results Consistent with the GALL Report.........3-2623.3.2.2  AMR Results Consistent with the GALL Report for Which FurtherEvaluation is Recommended.......................3-296 ix3.3.2.3  AMR Results Not Consistent with or Not Addressed in the GALLReport.........................................3-3193.3.3  Conclusion............................................3-3613.4  Aging Management of Steam and Power Conversion Systems...........3-3613.4.1  Summary of Technical Information in the Application............3-361 3.4.2  Staff Evaluation........................................3-3613.4.2.1  AMR Results Consistent with the GALL Report.........3-3723.4.2.2  AMR Results Consistent with the GALL Report for Which FurtherEvaluation is Recommended.......................3-3803.4.2.3  AMR Results Not Consistent with or Not Addressed in the GALLReport.........................................3-3893.4.3  Conclusion............................................3-3933.5  Aging Management of SC Supports................................3-3933.5.1  Summary of Technical Information in the Application............3-393 3.5.2  Staff Evaluation........................................3-3933.5.2.1  AMR Results Consistent with the GALL Report.........3-4083.5.2.2  AMR Results Consistent with the GALL Report for Which FurtherEvaluation is Recommended.......................3-4283.5.2.3  AMR Results Not Consistent with or Not Addressed in the GALLReport.........................................3-4573.5.3  Conclusion............................................3-4763.6  Aging Management of Electrical and Instrumentation and Controls System..3-4763.6.1  Summary of Technical Information in the Application............3-476 3.6.2  Staff Evaluation........................................3-4763.6.2.1  AMR Results Consistent with the GALL Report.........3-4803.6.2.2  AMR Results Consistent with the GALL Report for Which FurtherEvaluation is Recommended.......................3-4823.6.2.3  AMR Results Not Consistent with or Not Addressed in the GALLReport.........................................3-4873.6.3  Conclusion............................................3-5093.7  Conclusion for Aging Management Review Results....................3-510Time-limited Aging Analyses.................................................4-14.1  Identification of Time-Limited Aging Analyses..........................4-14.1.1  Summary of Technical Information in the Application..............4-1 4.1.2  Staff Evaluation..........................................4-2 4.1.3  Conclusion..............................................4-24.2  Reactor Vessel Neutron Embrittlement Analyses........................4-34.2.1  Reactor Vessel Fluence....................................4-44.2.1.1  Summary of Technical Information in the Application......4-4 4.2.1.2  Staff Evaluation...................................4-5 4.2.1.3  UFSAR Supplement...............................4-64.2.1.4  Conclusion.......................................4-74.2.2  Pressure-Temperature Limits................................4-74.2.2.1  Summary of Technical Information in the Application......4-7 4.2.2.2  Staff Evaluation...................................4-8 4.2.2.3  UFSAR Supplement...............................4-94.2.2.4  Conclusion......................................4-10 x4.2.3  Charpy Upper-Shelf Energy................................4-104.2.3.1  Summary of Technical Information in the Application.....4-10 4.2.3.2  Staff Evaluation..................................4-11 4.2.3.3  UFSAR Supplement..............................4-124.2.3.4  Conclusion......................................4-134.2.4  Adjusted Reference Temperature...........................4-134.2.4.1  Summary of Technical Information in the Application.....4-13 4.2.4.2  Staff Evaluation..................................4-14 4.2.4.3  UFSAR Supplement..............................4-154.2.4.4  Conclusion......................................4-154.2.5  Reactor Vessel Circumferential Welds Inspection Relief..........4-154.2.5.1  Summary of Technical Information in the Application.....4-15 4.2.5.2  Staff Evaluation..................................4-16 4.2.5.3  UFSAR Supplement..............................4-194.2.5.4  Conclusion......................................4-194.2.6  Reactor Vessel Axial Weld Failure Probability..................4-204.2.6.1  Summary of Technical Information in the Application.....4-20 4.2.6.2  Staff Evaluation..................................4-20 4.2.6.3  UFSAR Supplement..............................4-224.2.6.4  Conclusion......................................4-234.3  Metal Fatigue Analyses..........................................4-234.3.1  Class 1 Fatigue.........................................4-234.3.1.1  Reactor Pressure Vessel...........................4-24 4.3.1.2  Reactor Vessel Internals...........................4-28 4.3.1.3  Class 1 Piping and Components.....................4-294.3.2  Non-Class 1 Fatigue.....................................4-314.3.2.1  Summary of Technical Information in the Application.....4-31 4.3.2.2  Staff Evaluation..................................4-31 4.3.2.3  UFSAR Supplement..............................4-324.3.2.4  Conclusion......................................4-334.3.3  Effects of Reactor Water Environment on Fatigue Life...........4-334.3.3.1  Summary of Technical Information in the Application.....4-33 4.3.3.2  Staff Evaluation..................................4-34 4.3.3.3  UFSAR Supplement..............................4-384.3.3.4  Conclusion......................................4-384.4  Environmental Qualification Analyses for Electrical Components...........4-384.4.1  Summary of Technical Information in the Application.............4-39 4.4.2  Staff Evaluation.........................................4-39 4.4.3  UFSAR Supplement......................................4-404.4.4  Conclusion.............................................4-404.5  Concrete Containment Tendon Prestress Analysis......................4-414.5.1  Summary of Technical Information in the Application.............4-41 4.5.2  Staff Evaluation.........................................4-41 4.5.3  UFSAR Supplement......................................4-414.5.4  Conclusion.............................................4-414.6  Containment Liner Plate, Metal Containment, and Penetrations Fatigue Analysis....................................................4-41 4.6.1  Fatigue of the Torus......................................4-41 xi4.6.1.1  Summary of Technical Information in the Application.....4-414.6.1.2  Staff Evaluation..................................4-42 4.6.1.3  UFSAR Supplement..............................4-424.6.1.4  Conclusion......................................4-424.6.2  Fatigue of Safety Relief Valve Discharge Piping................4-434.6.2.1  Summary of Technical Information in the Application.....4-43 4.6.2.2  Staff Evaluation..................................4-43 4.6.2.3  UFSAR Supplement..............................4-444.6.2.4  Conclusion......................................4-444.6.3  Fatigue of Other Torus-Attached Piping.......................4-444.6.3.1  Summary of Technical Information in the Application.....4-44 4.6.3.2  Staff Evaluation..................................4-44 4.6.3.3  UFSAR Supplement..............................4-454.6.3.4  Conclusion......................................4-454.7  Other Time-Limited Aging Analyses.................................4-454.7.1  Reflood Thermal Shock of the Reactor Vessel Internals..........4-454.7.1.1  Summary of Technical Information in the Application.....4-45 4.7.1.2  Staff Evaluation..................................4-45 4.7.1.3  UFSAR Supplement..............................4-464.7.1.4  Conclusion......................................4-464.7.2  Time- Limited Aging Analysis in BWRVIPs....................4-464.7.2.1  BWRVIP-05, Reactor Vessel Axial Welds..............4-46 4.7.2.2  BWRVIP-25, Core Plate...........................4-47 4.7.2.3  BWRVIP-38, Shroud Support.......................4-504.7.2.4  BWRVIP-47, Lower Plenum Fatigue Analysis...........4-514.7.2.5  BWRVIP-48, Vessel ID Attachment Welds Fatigue Analysis...............................................4-524.7.2.6  BWRVIP-49, Instrument Penetrations Fatigue Analysis...4-52 4.7.2.7  BWRVIP-74, Reactor Pressure Vessel................4-53 4.7.2.8  BWRVIP-76, Core Shroud..........................4-544.8  Conclusion for Time-Limited Aging Analyses..........................4-55Review by the Advisory Committee on Reactor Safeguards.........................5-1 Conclusion..............................................................6-1 Appendix A:  VYNPS License Renewal Commitments.............................A-1Appendix B:  Chronology...................................................B-1Appendix C:  Principal Contributors............................................C-1Appendix D:  References...................................................D-1 xii TablesTable 1.4-1  Current Interim Staff Guidance..................................1-7Table 3.0.3-1  VYNPS Aging Management Programs..............................3-7Table 3.1-1  Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor CoolantSystem Components in the GALL Report.....................................3-150Table 3.2-1  Staff Evaluation for Engineered Safety Features Systems Components in theGALL Report...........................................................3-201Table 3.3-1  Staff Evaluation for Auxiliary System Components in the GALL Report....3-243Table 3.3-2  AMR Line Items for Elastomer Penetration Sealants...................3-287Table 3.3-3  AMR Line Item for Elastomer Seismic Isolation Joints.................3-289 Table 3.4-1  Staff Evaluation for Steam and Power Conversion Systems Components in theGALL Report...........................................................3-362Table 3.5-1  Staff Evaluation for SC Supports in the GALL Report..................3-394Table 3.5-2  Groundwater and Soil Sample Data from April 2002 Through April 2006...3-460Table 3.6-1  Staff Evaluation for Electrical and I&C Components in the GALL Report...3-477 xiiiABBREVIATIONSAACalternate ACACalternating current ACARaluminum conductor alloy reinforced ACIAmerican Concrete Institute ACRSAdvisory Committee on Reactor Safeguards ACSalternate cooling system ACSRaluminum core steel reinforced ADAMSAgencywide Document Access and Management System ADSautomatic depressurization system AEair evacuation AECAtomic Energy Commission AERMaging effect requiring management AFWauxiliary feedwater AISCAmerican Institute of Steel Construction AMaging management AMPaging management program AMRaging management review ANSIAmerican National Standards Institute AOGaugmented off-gas APCSBAuxiliary and Power Conversion Systems Branch ARTadjusted reference temperature ASauxiliary system ASMEAmerican Society of Mechanical Engineers ASTMAmerican Society for Testing and Materials ATWSanticipated transient without scram AWWAAmerican Water Works AssociationBAFbottom of the active fuelBLDbuilding drainage system BOPbalance of plant B&PVBoiler and Pressure Vessel BTPBranch Technical Position BWRboiling water reactor BWRVIPBoiling Water Reactor Vessel and Internals ProjectCADcontainment atmosphere dilutionCAPcorrective action program CASScast austenitic stainless steel CBIChicago Bridge & Iron CCWclosed cooling water CCWSclosed cooling water system CDcondensate demineralizer CDFcore damage frequency CEAcontrol element assembly CFchemistry factor xiv CFRCode of Federal RegulationsCIconfirmatory item CLBcurrent licensing basis CMAACrane Manufactures Association of America
 
CO 2carbon dioxideCPPUconstant pressure power uprate CRLcomponent record list CRDcontrol rod drive CRGTcontrol rod guide tube CScore spray CSScore spray system CSCScore standby cooling system CSTcondensate storage and transfer CUFcumulative usage factor CUFDreactor water cleanup unit filter demineralizer
 
C vUSECharpy upper-shelf energyCWcirculating water CWPcirculating water primingDBAdesign basis accidentDBEdesign basis event DCdirect current DGdiesel generator DLOdiesel lube oil DWdemineralized waterECCSemergency core cooling systemEDGemergency diesel generator EFPDeffective full power days EFPYeffective full-power year EICelectrical and instrumentation and control EMPACEnterprise Maintenance, Planning, and Control ENOEntergy Nuclear Operations, Inc.
Entergy VYEntergy Nuclear Vermont Yankee, LLC EOLend of life EPRIElectric Power Re search InstituteEPRI-MRPElectric Power Research Institute Materials Reliability Program EPUExtended Power Uprate EQEnvironmental qualification ERApplicant's Environmental Report - Operating License Renewal Stage ESextraction steam ESFengineered safety featureFAPfatigue action planFCVflow control valve FWfeedwater
 
F enenvironmental fatigue life correction factorFERCFederal Energy Regulatory Commission xvFFflency factorFIVflow-induced vibration FOfuel oil FPCfuel pool cooling FPFDfuel pool filter-demineralizer
 
FRFederal RegisterFSARfinal safety analysis report ft-lbfoot-pound FWfeedwaterGALLGeneric Aging Lessons Learned ReportGDCgeneral design criteria or general design criterion GEGeneral Electric GEISGeneric Environmental Impact Statement GLgeneric letter GSCgland seal condenser GSIgeneric safety issueHBheating boilerHCUhydraulic control unit HDheater drain HELBhigh-energy line break HPCIhigh pressure coolant injection HPCIShigh pressure coolant injection system HPSIhigh pressure safety injection HVACheating, ventilation, and air conditioning HVheater vent HWChydrogen water chemistry HXheat exchangerI&Cinstrumentation and controlsIAinstrument air IASCCirradiation assisted stress corrosion cracking IDinside diameter IEEEInstitute of Electrical and Electronics Engineers IGAintergranular attack IGSCCintergranular stress corrosion cracking INinformation notice INELIdaho National Engineering Laboratory INPOInstitute of Nuclear Power Operations IPAintegrated plant assessment IPEindividual plant examination IRinsulation resistance ISAInstrument Society of America ISGinterim staff guidance ISIinservice inspection ISPintegrated surveillance program xviISTinservice testingJDDJohn Deere diesel ksi1000 pounds per square inchKV or kVkilo-volt KWkilo-wattLOCAloss of coolant accidentLPCIlow pressure coolant injection LRAlicense renewal application LRBDlicense renewal boundary drawings LRISLicense Renewal Information System LRPGlicense renewal project guidelineMEBmetal-enclosed busMeVmega-electron volt MGmotor generator MGLOmotor generator lube oil MICmicrobiologically influenced corrosion MSmain stream MSIVmain stream isolation valve MUDmake-up demineralizer MWemegawatts-electric MWtmegawatts-thermal N 2nitrogenNaOHsodium hydroxide NBnuclear boiler NBVISnuclear boiler vessel instrumentation system n/cm 2neutrons per square centimeterNDEnondestructive examination NEINuclear Energy Institute NESCNational Electric Safety Code NFPANational Fire Protection Association NPSnominal pipe size NRCUS Nuclear Regulatory Commission NSACNuclear Science Advisory Committee NSSSnuclear steam supply system NUMARCNuclear Management and Resources Council (now NEI)
NUREGUS Nuclear Regulatory Commission Regulatory Guide NUREG/CRUS Nuclear Regulatory Commission Regulatory Guide contractor report NWCnormal water chemistryODSCCoutside-diameter stress corrosion crackingOEoperating experience OIopen item xviiPASSpost-accident sampling systemPCACprimary containment atmosphere control pHpotential hydrogen P&IDpiping and instrumentation diagram ppmparts per million P-Tpressure-temperature PTSpressurized thermal shock PUSARpower uprate safety analysis report PVCpolyvinyl chloride PWpotable water PWRpressurized water reactor PWSCCprimary water stress corrosion crackingQAquality assuranceQ&Aquestion and answerRAIrequest for additional informationRBCCWreactor building closed cooling water RCICreactor core isolation cooling RCPBreactor coolant pressure boundary RCSreactor coolant system RDWradwaste RFOrefueling outage RGregulatory guide RHRSresidual heat removal system RHRSWresidual heat removal service water RIPretired in place RPVreactor pressure vessel RRPreactor recirculation pump RRSreactor recirculation system RTradiographic testing RTDresistance temperature detector
 
RT NDTreference temperature nil ductility transitionRVreactor vessel RVIreactor vessel internals RVIDreactor vessel integrity database RWCUreactor water cleanupSAservice airSBFPCstandby fuel pool cooling SBGTstandby gas treatment SBOstation blackout SCstructure and component SCCstress-corrosion cracking SEsafety evaluation SERsafety evaluation report SFPspent fuel pool SIFstress intensification factor xviiiSLCstandby liquid controlSOseal oil SPL sampling SOCstatement of consideration SRPStandard Review Plan SRP-LRStandard Review Plan for Review of License Renewal Applications for NuclearPower PlantsSRVsafety relief valve SSstainless steel SSCsystem, structure, and component SSEsafe-shutdown earthquake SWservice water SWSservice water systemsTBCCWturbine building closed cooling waterTGturbine generator TLAAtime-limited aging analysis TLOturbine lube oil TStechnical specificationsUFSARupdated final safety analysis reportUSARupdated safety analysis report USASUnited States of America Standard USEupper-shelf energy UTultrasonic testing UVultra violetVHSVernon Hydroelectric StationVTvisual testing VYNPSVermont Yankee Nuclear Power Station1/4 Tone-fourth of the way through the vessel wall 1-1 SECTION 1INTRODUCTION AND GENERAL DISCUSSION 1.1  IntroductionThis document is a safety evaluation report (SER) on the license renewal application (LRA) forVermont Yankee Nuclear Power Station (VYNPS), as filed by Entergy Nuclear Operations, Inc.
(ENO or the applicant). By letter dated January 25, 2006, ENO submitted its application to the United States (US) Nuclear Regulatory Commission (NRC) for renewal of the VYNPS operating license for an additional 20 years. The NRC staff (the staff) prepared this report to summarize the results of its safety review of the LRA for compliance with Title 10, Part 54, of the Code ofFederal Regulations, "Requirements for Renewal of Operating Licenses for Nuclear PowerPlants" (10 CFR Part 54). The NRC project manager for the license renewal review is Jonathan Rowley. Mr. Rowley may be contacted by telephone at 301-415-4053 or by electronic mail at JGR@nrc.gov. Alternatively, written correspondence may be sent to the following address:Division of License RenewalUS Nuclear Regulatory Commission Washington, DC 20555-0001 Attention: Jonathan Rowley, Mail Stop 011-F1In its January 25, 2006 submission letter, the applicant requested renewal of the operatinglicense issued in accordance with Section 104b (Operating License No. DPR-28) of the Atomic Energy Act of 1954, as amended, for VYNPS for a period of 20 years beyond the current expiration at midnight March 21, 2012. VYNPS is located approximately five miles south of Brattleboro, Vermont. The NRC issued the VYNPS construction permit on December 11, 1967, and the operating license on February 28, 1973. VYNPS is of a Mark 1 Boiling Water Reactor (BWR) design. General Electric supplied the nuclear steam supply system (NSSS) and Ebasco originally designed and constructed the plant. The VYNPS licensed power output is 1912 megawatt thermal with a gross electrical output of approximately 650 megawatt electric.
The updated final safety analysis report (UFSAR) contains details of the plant and the site.The license renewal process consists of two concurrent reviews, a technical review of safetyissues and an environmental review. The NRC regulations in 10 CFR Part 54 and 10 CFR Part 51, "Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions," respectively, set forth requirements for these reviews. The safety review for the VYNPS license renewal is based on the applicant's LRA and responses to staff requestsfor additional information. The applicant supplemented the LRA and provided clarifications through its responses to the staff's requests for additional information in audits, meetings, and docketed correspondence. Unless otherwise noted, the staff reviewed and considered information submitted through July 3, 2007 January XX, 2008. The staff reviewed informationreceived after that date case by case depending on the stage of the safety review and the volume and complexity of the information. The public may view the LRA and all pertinent information and materials, including the UFSAR, at the NRC Public Document Room, on the first floor of One White Flint North, 11555 Rockville Pike, Rockville, MD 20852-2738 1-2 (301-415-4737 / 800-397-4209), and at Dickinson Memorial Library, 115 Main St., Northfield,MA 01360. In addition, the public may find the LRA, as well as materials related to the license renewal review, on the NRC web site at http://www.nrc.gov.This SER summarizes the results of the staff's safety review of the LRA and describes thetechnical details considered in evaluating the safety aspects of the unit's proposed operation for an additional 20 years beyond the term of the current operating license. The staff reviewed the LRA in accordance with the NRC regulations and the guidance in the US NRC NUREG-1800, Revision 1, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR), dated September 2005.SER Sections 2 through 4 address the staff's evaluation of license renewal issues consideredduring the review of the LRA. SER Section 5 is reserved for the report of the Advisory Committee on Reactor Safeguards (ACRS). SER Section 6 presents the conclusions of this report.SER Appendix A is a table of the applicant's commitments for renewal of the operating license.SER Appendix B is a chronology of the principal correspondence between the staff and the applicant on the LRA review. SER Appendix C is a list of principal contributors to this SER. Appendix D is a bibliography of the references in support of the staff's review.In accordance with 10 CFR Part 51, the staff prepared a plant-specific supplement toNUREG-1437, "Generic Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS)." This supplement discusses the environmental considerations related to the VYNPS license renewal. The staff issued a plant-specific supplement to the GEIS, "Generic Environmental Impact Statement for License Renewal of Nuclear Plants Supplement 30 Regarding Vermont Yankee Nuclear Power Station," on August 1, 2007.1.2  License Renewal BackgroundPursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating licenses for commercial power reactors are issued for 40 years. These licenses can be renewed for up to 20 additional years. The original 40-year license term was selected on the basis of economic and antitrust considerations, rather than on technical limitations; however, some individual plant and equipment designs may have been engineered based on an expected 40-year service life.In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear powerplant aging. This workshop led the NRC to establish a comprehensive program plan for nuclear plant aging research. From the results of that research, a technical review group concluded that many aging phenomena are readily manageable and pose no technical issues for life extension of nuclear power plants. In 1986, the staff published a request for comment on a policy statement that would address major policy, technical, and procedural issues related to license renewal for nuclear power plants.
1-3In 1991, the staff published the license renewal rule in 10 CFR Part 54 (Volume 56,page 64943, of the Federal Register (56 FR 64943), dated December 13, 1991). The staffparticipated in an industry-sponsored demonstration program to apply 10 CFR Part 54 to a pilot plant and to gain experience necessary to develop implementation guidance. To establish a scope of review for license renewal, 10 CFR Part 54 defined age-related degradation unique to license renewal. However, during the demonstration program, the staff found that many aging effects on plant systems and components are managed during the period of initial license. In addition, the staff found that the scope of the review did not allow sufficient credit for existing programs, particularly the implementation of 10 CFR 50.65, which also manages plant-aging phenomena. As a result, the staff amended 10 CFR Part 54 in 1995. As published in 60 FR 22461, dated May 8, 1995, the amended 10 CFR Part 54 establishes a regulatory process that is simpler, more stable, and more predictable than the previous 10 CFR Part 54 process. In particular, as amended, 10 CFR Part 54 focuses on the management of adverse aging effects rather than on identifying age-related degradation unique to license renewal. The staff initiated these rule changes to ensure that important systems, structures, and components (SSCs) will continue to perform their intended functions during periods of extended operation. In addition, the revised 10 CFR Part 54 rule clarifies and simplifies the integrated plant assessment for consistency with the revised focus on passive, long-lived structures and components (SCs).In parallel with these initiatives, the NRC pursued a separate rulemaking effort (61 FR 28467,dated June 5, 1996) and developed an amendment to 10 CFR Part 51 to focus the scope of the review of license renewal environmental impacts and to fulfill the NRC's responsibilities in accordance with the National Environmental Policy Act of 1969.1.2.1  Safety ReviewLicense renewal requirements for power reactors are based on two key principles:  (1)The regulatory process is adequate to ensure that the licensing bases of all currentlyoperating plants maintain an acceptable level of safety, with the possible exception of the detrimental aging effects on the functions of certain SSCs, as well as a few other safety-related issues, during the period of extended operation.  (2)The plant-specific licensing basis must be maintained during the renewal term in thesame manner and to the same extent as during the original licensing term.In implementing these two principles, 10 CFR 54.4, "Scope," defines the scope of licenserenewal as including those SSCs that (1) are safety-related, (2) the failure of which could affect safety-related functions, or (3) are relied on for compliance with the NRC fire protection, environmental qualification (EQ), pressurized thermal shock (PTS), anticipated transient without scram (ATWS), and station blackout (SBO) regulations.Pursuant to 10 CFR 54.21(a), a license renewal applicant must review all SSCs within thescope of 10 CFR Part 54 to identify SCs subject to an aging management review (AMR). SCs subject to an AMR perform an intended function without moving parts or without a change in configuration or properties and are not subject to replacement after a qualified life or specified time period. As required by 10 CFR 54.21(a), license renewal applicants must demonstrate that the aging effects will be managed so that the intended function(s) of those SCs will be 1-4maintained consistent with the current licensing basis (CLB) for the period of extendedoperation. However, active equipment is considered to be adequately monitored and maintained by existing programs. In other words, detrimental aging effects that may affect active equipment are readily detectable and can be identified and corrected through routine surveillance, performance monitoring, and maintenance. Surveillance and maintenance programs for active equipment, as well as other maintenance aspects of plant design and licensing basis, are required throughout the period of extended operation.Pursuant to 10 CFR 54.21(d), the LRA is required to include a UFSAR supplement that musthave a summary description of the applicant's programs and activities for managing aging effects and an evaluation of time-limited aging analyses (TLAAs) for the period of extended operation.License renewal also requires TLAA identification and updating. During the plant design phase,certain assumptions were made about the length of time the plant can operate. These assumptions were incorporated into design calculations for several plant SSCs. In accordance with 10 CFR 54.21(c)(1), the applicant must either show that these calculations will remain valid for the period of extended operation, project the analyses to the end of the period of extended operation, or demonstrate that the aging effects on these SSCs will be adequately managed for the period of extended operation.In 2001, the NRC developed and issued Regulatory Guide (RG) 1.188, "Standard Format andContent for Applications to Renew Nuclear Power Plant Operating Licenses." This RG endorses Nuclear Energy Institute (NEI) 95-10, Revision 3, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule," issued in March 2001. NEI 95-10 details an acceptable method of implementing 10 CFR Part 54. The staff also used the SRP-LR in reviewing the LRA.In the LRA, the applicant fully utilized the process defined in NUREG-1801, Revision 1,"Generic Aging Lessons Learned (GALL) Report," dated September  2005. The GALL Report summarizes staff-approved aging management programs (AMPs) for the aging of many SCs subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and resources to review the LRA can be greatly reduced, improving the efficiency and effectiveness of the license renewal review process. The GALL Report summarizes the aging management evaluations, programs, and activities credited for managing aging for most SCs throughout the industry. The report is also a quick reference for both the applicant and staff reviewers to AMPs and activities that can provide adequate aging management during the period of extended operation.1.2.2  Environmental ReviewPart 51 of 10 CFR governs environmental protection regulations. In December 1996, the staffrevised the environmental protection regulations to facilitate the environmental review for license renewal. The staff prepared the Generic Environmental Impact Statement (GEIS) to document its evaluation of the possible environmental impacts of nuclear power plant license renewals. For certain environmental impacts, the GEIS establishes findings applicable to all nuclear power plants. These generic findings are codified in Appendix B, "Environmental Effect of Renewing the Operating License of a Nuclear Power Plant," to Subpart A, "National 1-5Environmental Policy Act - Regulations Implementing Section 102(2)," of 10 CFR Part 51.Pursuant to 10 CFR 51.53(c)(3)(i), license renewal applicants may incorporate these generic findings in their environmental reports. In accordance with 10 CFR 51.53(c)(3)(ii), an environmental report must also include analyses of environmental impacts that must be evaluated on a plant-specific basis (i.e., Category 2 issues).In accordance with the National Environmental Policy Act of 1969 and 10 CFR Part 51, the staffreviewed the plant-specific environmental impacts of license renewal, including whether the GEIS had not considered new and significant information. As part of its scoping process, the staff held a public meeting on June 7, 2006, in Brattleboro, Vermont, to identify plant-specific environmental issues. Draft, plant-specific GEIS Supplement 30 documents the results of the environmental review and makes a preliminary recommendation as to the license renewal action. The staff held another public meeting on January 31, 2007, in Brattleboro, Vermont, to discuss draft, plant-specific GEIS Supplement 30.1.3  Principal Review MattersPart 54 of 10 CFR describes the requirements for renewing operating licenses for nuclear power plants. The staff's technical review of the LRA was in accordance with NRC guidance and the requirements of 10 CFR Part 54. Section 54.29, "Standards for Issuance of a Renewed License," of 10 CFR sets forth the standards for license renewal. This SER describes the results of the staff's safety review.In accordance with 10 CFR 54.19(a), the NRC requires license renewal applicants to submitgeneral information. The applicant provided this general information in LRA Section 1. The staff reviewed LRA Section 1 and finds that the applicant has submitted the information required by 10 CFR 54.19(a).In accordance with 10 CFR 54.19(b), the NRC requires that LRAs include "conforming changesto the standard indemnity agreement, 10 CFR 140.92, Appendix B, to account for the expiration term of the proposed renewed license." On this issue, in the LRA, the applicant stated:The agreement shall terminate at the time of expiration of the license specified inItem 3 of the attachment to the agreement, which is the last to expire. Item 3 of the attachment to the indemnity agreement, as revised by Amendment No. 6, lists VYNPS operating license number DPR-28. ENO requests that conforming changes be made to Article VII of the indemnity agreement, and Item 3 of the attachment to that agreement, specifying the extension of agreement until the expiration date of the renewed VYNPS facility operating license sought in this application. In addition, should the license number be changed upon issuance of the renewal license, ENO requests that conforming changes be made to Item 3 of the attachment and other sections of the indemnity agreement as appropriate.The staff intends to maintain the original license number upon issuance of the renewed license,if approved. Therefore, conforming changes to the indemnity agreement need not be made and the requirements of 10 CFR 54.19(b) have been met.
1-6In accordance with 10 CFR 54.21,"Contents of Application - Technical Information," the NRCrequires that LRAs contain (a) an integrated plant assessment, (b) a description of any current licensing basis (CLB) changes occurring during the staff's review of the LRA, (c) an evaluation of TLAAs, and (d) a UFSAR supplement. LRA Sections 3 and 4 and Appendix B address the license renewal requirements of 10 CFR 54.21(a), 10 CFR 54.21(b), and 10 CFR 54.21(c). LRA Appendix A satisfies the license renewal requirements of 10 CFR 54.21(d).In accordance with 10 CFR 54.21(b), the NRC requires that each year following submission ofthe LRA and at least three months before the scheduled completion of the staff's review, the applicant submit an LRA amendment identifying any CLB changes of the facility that materially affect the contents of the LRA, including the UFSAR supplement.In accordance with 10 CFR 54.22, "Contents of Application - Technical Specifications," the NRCrequires that the LRA include changes or additions to the technical specifications necessary tomanage the aging effects during the period of extended operation. In LRA Appendix D, the applicant stated that it had not identified any technical specification changes necessary to support issuance of the renewed VYNPS operating license. This statement adequately addresses the 10 CFR 54.22 requirement.The staff evaluated the technical information required by 10 CFR 54.21 and 10 CFR 54.22 inaccordance with NRC regulations and SRP-LR guidance. SER Sections 2, 3, and 4 document the staff's evaluation of the technical information in the LRA.As required by 10 CFR 54.25, "Report of the Advisory Committee on Reactor Safeguards," theACRS will issue a report documenting its evaluation of the staff's LRA review and SER. SER Section 5 will incorporate the ACRS report when issued. SER Section 6 will document the findings required by 10 CFR 54.29.The final, plant-specific GEIS Supplement 30 will document the staff's evaluation of theenvironmental information required by 10 CFR 54.23, "Contents of Application - Environmental Information," and will specify the considerations related to the VYNPS operating license renewal. The staff will prepare this supplement separately from the SER.1.4  Interim Staff GuidanceLicense renewal is a living program. The staff, industry, and other interested stakeholders gain experience and develop lessons learned with each renewed license. The lessons learned address the staff's performance goals of maintaining safety, improving effectiveness and efficiency, reducing regulatory burden, and increasing public confidence. Interim staff guidance (ISG) is documented for use by the staff, industry, and other interested stakeholders until incorporated into such license renewal guidance documents as the SRP-LR and the GALL Report.Table 1.4-1 shows the current set of interim staff guidance (ISGs), as well as the SER sectionsin which the staff addresses them.
1-7Table 1.4-1  Current Interim Staff GuidanceISG Issue(Approved ISG Number)PurposeSER SectionNickel-alloy components in the reactor coolant pressure boundary(LR-ISG-19B)Cracking of nickel-alloy components in the reactor pressure boundary.ISG under development. NEI andEPRI-MRP will develop an
 
augmented inspection program for GALL AMP XI.M11-B. This AMP will not be completed until the NRC approves an augmented inspection program for nickel-alloy base metal components and welds as proposed by EPRI-MRP.Not applicable [Pressurized WaterReactors (PWRs )only]Corrosion of drywell shell in Mark I containments(LR-ISG-2006-01)To address concerns related tocorrosion of drywell shell in Mark I
 
containments.
3.5.2.2.11.5  Summary of Open ItemsAs a result of its review of the LRA, including additional information submitted to the staffthrough July 3, 2007, the staff determined that no open items exist which would require a formal response from the applicant. An item would have been considered open if the applicant had not presented a sufficient basis for resolution of an issue.1.6  Summary of Confirmatory ItemsAs a result of its review of the LRA, including additional information submitted to the staff through March 23, 2007, the staff identified the following confirmatory items (CIs). An item was considered confirmatory if the staff and the applicant had reached a satisfactory resolution, but the resolution had not been submitted to the staff. Each CI was assigned a unique identifying number. By letters dated July 3, July 30, and August 16, 2007, the applicant responded to these CIs. The staff reviewed these responses and closed each of the CIs. The basis for closing the CIs is as follows:CI 2.3.3.2a-1License renewal drawing LRA-G-191159-SH-01-0, at location H-11, depicts pipe section2"-SW-566C as within the scope of license renewal. The license renewal boundary flag for 2"-SW-566C is located on an unisolable section of pipe. The actual location of the license renewal scope boundary for this pipe section is not clear. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components meet the requirements of 10 CFR 54.4(a)(2).
1-8In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRCLicense Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the regional inspection team stated in part that the applicant has included in-scope for spatial interaction the portion of the SW system in the service water pump area of the intake structure and the reactor building. Pipe section 2" SW-566C is in the reactor building and is therefore in-scope for spatial interaction. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Further, the applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 indicates that pipe section 4" SW-567 which attaches to pipe section 2" SW-566C is in-scope for spatial interaction.Based on its review, the staff found the above response acceptable because the inspectionteam and the applicant acknowledged that service water pipe 2" SW-566C is within the scope of license renewal and subject to an AMR based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). Therefore, the staff concern described in Inspection Item 2.3.3.2a-1 is resolved.CI 2.3.3.2a-2LRA Section 2.1.2.1.2 states in part that nonsafety-related piping systems connected tosafety-related systems were included up to the structural boundary or to a point that includes an adequate portion of the nonsafety-related piping run to conservatively include the first seismic or equivalent anchor. In addition, if isometric drawings were not readily available to identify the structural boundary, connected lines were included to a point beyond the safety/nonsafety interface, like a base-mounted component, flexible connection, or the end of a piping run (i.e , adrain line).It is not clear whether the nonsafety-related piping systems were included up to the structuralboundary or to a point that includes an adequate portion of the nonsafety-related piping run to include the first seismic or equivalent anchor. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(2).In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRCLicense Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated in part that for structural support considerations, the applicant has included components outside the safety class pressure boundary, yet relied upon to provide structural/seismic support for the pressure boundary. The application describes the types of components which are included in the scope of license renewal for 10 CFR 54.4(a)(2) and subject to an AMR in the service water system in LRA Table 2.3.3-13-42. This table was developed by including all nonsafety-related portions of fluid systems which are located within a building containing safety-related components and all nonsafety-related piping connected to safety-related systems back to the structural boundary using an isometric drawing. In cases where an isometric drawing which depicts the structural boundary is not readily available, connected lines were included back to a point beyond the 1-9safety/nonsafety interface to a base-mounted component, flexible connection, or the end of apiping run (such as a drain line) in accordance with the response to RAI 2.1-2. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings.Further, the applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2states that there are no nonsafety-related systems for which the applicant has not identified the nonsafety-related portions of systems which are attached to safety-related systems and required to be in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). However, as a result of discussions with the staff during the Region I inspection (February 2007), the applicant determined that some safety-related SSCs in the VY turbine building required consideration for potential spatial impacts from nonsafety-related SSCs based on 10 CFR 54.4(a)(2). Therefore, an expanded review for SSCs in the turbine building determined that additional components required an AMR. Those additional component types have been added to LRA Table 2.3.3-13-42, as addressed in the applicant's letters to the NRC dated July 30, 2007 and August 16, 2007.Based on its review, the staff found the above response acceptable because the applicantstated that there are no nonsafety-related portions of systems which are attached to safety-related systems that are not within the scope of license renewal in accordance with 10 CFR 54.4(a)(2), but that there were spatial impact concerns from nonsafety-related SSCs in the turbine building. The additional component types have been added to LRA Table 2.3.3-13-42.
Therefore, the staff concern described in Inspection Item 2.3.3.2a-2 is resolved.CI 2.3.3.12-1LRA Section 2.3.3.12 indicates that the John Deere Diesel (JDD) is installed in compliance with10 CFR 50, Appendix R, requirements. However, due to a lack of available drawings and/or detailed description of the diesel equipment listed in LRA Table 2.3.3-12, it is difficult to determine if any AMR category components may have been omitted from the table. It is recommended that the JDD be inspected to assure all AMR category components are included in the list of LRA Table 2.3.3-12. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(3).In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRCLicense Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated that the John Deere diesel system components are listed in LRA Table 2.3.3-12 and the supporting fuel oil day tank, fiberglass underground storage tank, and supply lines are listed in LRA Table 2.3.3-6, "Fuel Oil System." Based on its review, the staff found the above response acceptable because the NRC RegionalInspection Team verified that all components subject to an AMR are included in LRA Table 2.3.3-12 and LRA Table 2.3.3-6 and confirmed that no other portions of the John Deere diesel system should have been included within scope based on 10 CFR 54.4(a)(3). Therefore, the staff concern described in Inspection Item 2.3.3.12-1 is resolved.
1-10CI 2.3.3.13a-1The LRA states that the augmented off-gas system is within the scope of license renewal basedon requirements of 10 CFR 54.4(a)(2) because of the potential for physical interaction with safety-related components described in LRA Table 2.3.3.13-A. The determination of whether a component meets the requirements of 10 CFR 54.4(a)(2) for physical interactions is based on where it is located in a building and its proximity to safety-related equipment or where a structural/seismic boundary exists. This information is not provided on license renewal drawings nor was a detailed description provided in the LRA. Consequently, any omission of augmented off-gas components subject to an AMR cannot be determined. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components meet the requirements of 10 CFR 54.4(a)(2) and all the components subject to an AMR are included in LRA Table 2.3.3-13-1.In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRCLicense Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team noted LRA Table 2.3.3.13-B states that the portion of the AOG system associated with the plant stack loop seal is subject to an AMR based on 10 CFR 54.4(a)(2) for physical interactions. Since the boundaries for the portion of the system as described in LRA Table 2.3.3.13-B were not well defined, in its letter dated July 30, 2007, the applicant amended the table to read "portion of the system inside the plant stack." The inspector walked down the remainder of the system and confirmed that no other portions of the system should have been included based on 10 CFR 54.4(a)(2).Based on its review, the staff found the above response acceptable because the applicantamended LRA Table 2.3.3.13-B as appropriate and the NRC regional inspector walked down the remainder of the AOG system outside the plant stack and confirmed that no other portions of the system should have been included within scope based on 10 CFR 54.4(a)(2). Therefore, the staff concern described in Inspection Item 2.3.3.13a-1 is resolved.CI 2.3.3.13e-1 The LRA states that the circulating water system is within the scope of license renewal basedon the potential for physical interaction with safety-related components as required by 10 CFR 54.4(a)(2) and described in LRA Table 2.3.3.13-A. The applicant did not provide drawings highlighting in-scope components required by 10 CFR 54.4(a)(2), stating that the drawings would not provide significant additional information because they do not indicate proximity of components to safety-related equipment and do not identify structural/seismic boundaries. Without license renewal drawings and/or detailed description of the circulating water system, the omission of components subject to an AMR cannot be determined (see LRA Table 2.3.3-13-9). The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(2) and all the components subject to an AMR are included in LRA Table 2.3.3-13-9.
1-11In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRCLicense Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope. Further, applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 states that there are no nonsafety-related systems for which the applicant has not identified the nonsafety-related portions of systems which are attached to safety-related systems and required to be in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). However, as a result of discussions with the staff during the Region I inspection (February 2007), the applicant determined that some safety-related SSCs in the VY turbine building required consideration for potential spatial impacts from nonsafety-related SSCs in accordance with 10 CFR 54.4(a)(2). Therefore, an expanded review for SSCs in the turbine building determined that additional components required an AMR. Those additional component types were added to LRA Table 2.3.3-13-9, as addressed in the applicant's letters to the staff dated July 30, 2007 and August 16, 2007.Based on its review, the staff found the above response acceptable because the applicantstated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope in accordance with 10 CFR 54.4(a)(2) but that there were spatial impact concerns from nonsafety-related SSCs in the turbine building. The additional component types have been added to LRA Table 2.3.3-13-9. Therefore, the staff concern regarding components of the CW system described in Inspection Item 2.3.3.13e-1 is resolved.CI 2.3.3.13m-1 The LRA states that the reactor water clean up system is within the scope of license renewal inaccordance with 10 CFR 54.4(a)(2) because of the potential for physical interaction with safety-related components as described in LRA Table 2.3.3.13-A. The determination of whether a component meets the requirements of 10 CFR 54.4(a)(2) for physical interactions is based on where it is located in a building and its proximity to safety-related equipment or where a structural/seismic boundary exists. This information is not provided on license renewal drawings nor was a detailed description provided in the LRA. Consequently, any omission of the reactor water clean up components subject to an AMR cannot be determined. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(2) and all the components subject to an AMR are included in LRA Table 2.3.3-13-36.In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRCLicense Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope. Further, the applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 states that there are no nonsafety-related systems for which the applicant has not identified the nonsafety-related portions of systems which are attached to safety-related systems and required to be in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The 1-12applicant also stated that there were no additional components that should be within scopebased on 10 CFR 54.4(a) as identified during the NRC Regional Inspection and subsequent applicant reviews.Based on its review, the staff found the above response acceptable because the applicantstated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope in accordance with 10 CFR 54.4(a)(2) and that there were no additional components identified that should be in-scope based on 10 CFR 54.4(a). Therefore, the staff concern regarding the components of the RWCU system described in Inspection Item 2.3.3.13m-1 is resolved.1.7  Summary of Proposed License ConditionsFollowing the staff's review of the LRA, including subsequent information and clarifications provided by the applicant, the staff identified three proposed license conditions.The first license condition requires the applicant to include the UFSAR supplement required by10 CFR 54.21(d) in the next UFSAR update, as required by 10 CFR 50.71(e), following the issuance of the renewed license.The second license condition requires future activities identified in the UFSAR supplement to becompleted prior to the period of extended operation.The third license condition requires that all capsules in the reactor vessel, that are removed andtested, must meet the requirements of American Society for Testing and Materials (ASTM) E 185-82 to the extent practicable for the configuration of the specimens in the capsule. Any changes to the capsule withdrawal schedule, including spare capsules, must be approved by the staff prior to implementation. All capsules placed in storage must be maintained for future insertion. Any changes to storage requirements must be approved by the staff as required by 10 CFR Part 50, Appendix H.
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2-1 SECTION  2STRUCTURES AND COMPONENTS SUBJECT TO AGINGMANAGEMENT REVIEW 2.1  Scoping and Screening Methodology2.1.1  IntroductionTitle 10, Section 54.21, of the Code of Federal Regulations (CFR), "Contents of ApplicationTechnical Information" (10 CFR 54.21), requires for each license renewal application (LRA) an integrated plant assessment (IPA) listing structures and components (SCs) subject to an aging management review (AMR) from all of the systems, structures, and components (SSCs) within the scope of license renewal.LRA Section 2.1, "Scoping and Screening Methodology," describes the methodology foridentifying SSCs at the Vermont Yankee Nuclear Power Station (VYNPS) within the scope of license renewal and SCs subject to an AMR. The staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff) reviewed the Entergy Nuclear Operations, Inc. (ENO or the applicant) scoping and screening methodology to determine whether it meets the scoping requirements of 10 CFR 54.4(a) and the screening requirements of 10 CFR 54.21.In developing the scoping and screening methodology for the LRA, the applicant considered therequirements of 10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants" (the Rule), statements of consideration on the Rule, and the guidance of Nuclear Energy Institute (NEI) 95-10, Revision 6, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule," dated June 2005. The applicant also considered the correspondence between the staff, other applicants, and the NEI.2.1.2  Summary of Technical Information in the ApplicationLRA Sections 2 and 3 state the technical information required by 10 CFR 54.4 and 54.21(a).LRA Section 2.1 describes the process for identifying SSCs meeting the license renewal scoping criteria of 10 CFR 54.4(a) and the process for identifying SCs subject to an AMR as required by 10 CFR 54.21(a)(1). The applicant provided the results of the process for identifying such SCs in the following LRA sections:
* Section 2.2, "Plant Level Scoping Results"
* Section 2.3, "Scoping and Screening Results: Mechanical Systems"
* Section 2.4, "Scoping and Screening Results: Structures"
* Section 2.5, "Scoping and Screening Results: Electrical and Instrumentation and ControlSystems" 2-2LRA Section 3, "Aging Management Review Results," states the applicant's aging managementresults in the following LRA sections:
* Section 3.1, "Reactor Vessel, Internals and Reactor Coolant System"
* Section 3.2, "Engineered Safety Features Systems"
* Section 3.3, "Auxiliary Systems"
* Section 3.4, "Steam and Power Conversion Systems"
* Section 3.5, "Structures and Component Supports"
* Section 3.6, "Electrical and Instrumentation and Controls"LRA Section 4, "Time-Limited Aging Analyses," states the applicant's evaluation of time-limitedaging analyses.2.1.3  Scoping and Screening Program ReviewThe staff evaluated the LRA scoping and screening methodology in accordance with theguidance in Section 2.1, NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants," Revision 1, (SRP-LR), and the Nuclear Energy Institute (NEI) 95-10, "Industry Guidelines for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule," Revision 6, (NEI 95-10). The following regulations form the basis for the acceptance criteria for the scoping and screening methodology review:
* 10 CFR 54.4(a) as to identification of plant SSCs within the scope of the Rule
* 10 CFR 54.4(b) as to identification of the intended functions of plant systems andstructures within the scope of the Rule
* 10 CFR 54.21(a)(1) and 10 CFR 54.21(a)(2) as to the methods utilized by the applicantto identify plant SCs subject to an AMRWith the guidance of the corresponding SRP-LR sections, the staff reviewed, as part of theapplicant's scoping and screening methodology, the activities described in the following LRA
 
sections:
* Section 2.1 to ensure that the applicant described a process for identifying SSCs withinthe scope of license renewal in accordance with 10 CFR 54.4(a)
* Section 2.2 to ensure that the applicant described a process for identifying SCs subjectto an AMR in accordance with 10 CFR 54.21(a)(1) and 10 CFR 54.21(a)(2)The staff conducted a scoping and screening methodology audit at VYNPS in Vernon, Vermontduring the week of April 24-28, 2006. The audit focused on whether the applicant had developed and implemented adequate guidance for the scoping and screening of SSCs by the methodologies in the LRA and the requirements of the Rule. The staff reviewed implementation of the project level guidelines and topical reports describing the applicant's scoping and screening methodology. The staff discussed with the applicant details of the implementation and control of the license renewal program and reviewed administrative control documentation and selected design documentation used by the applicant during the scoping and screening process. The staff reviewed the applicant's processes for quality assurance (QA) for development of the LRA. The staff reviewed the quality attributes of the applicant's aging 2-3management program (AMP) activities described in LRA Appendix A, "Updated Final SafetyAnalysis Report Supplement," and LRA Appendix B, "Aging Management Programs and Activities" and the LRA training and qualification development team. The staff reviewed scoping and screening results reports for the core spray (CS) system and intake structure for the applicant's appropriate implementation of the methodology outlined in the administrative controls and for results consistent with the current licensing basis (CLB) documentation. 2.1.3.1  Implementation Procedures and Documentation Sources for Scoping andScreeningThe staff reviewed the applicant's scoping and screening implementation procedures asdocumented in the audit report dated August 10, 2006 to verify whether the process for identifying SCs subject to an AMR was consistent with the LRA and the SRP-LR. Additionally, the staff reviewed the scope of CLB documentation sources and the applicant's process for appropriate consideration of CLB commitments and for adequate implementation of the procedural guidance during the scoping and screening process.2.1.3.1.1  Summary of Technical Information in the Application In LRA Section 2.1, the applicant addressed the following information sources for the licenserenewal scoping and screening process:
* System and Topical Design Basis Documents (DBDs)
* VYNPS Enterprise Maintenance, Planning, and Control (EMPAC) Component Database
* Updated Final Safety Analysis Report (UFSAR)
* Appendix R Safe Shutdown Capability Assessment
* Fire Hazards Analysis Report
* Safe Shutdown Capability Assessment
* Technical Specifications
* Maintenance Rule Scoping Basis Documents
* Safety Classification Documents
* Plant Layout Drawings The applicant stated that it used this information to identify the functions performed by plantsystems and structures. It then compared these functions to the scoping criteria in 10 CFR 54.4(a)(1-3) to determine whether the associated plant system or structure performed a license renewal intended function. It also used these sources to develop the list of SCs subject to an AMR.The license renewal boundary drawings (LRBDs) show the systems within the scope of licenserenewal highlighted in color.
2-42.1.3.1.2  Staff EvaluationScoping and Screening Implementation Procedures. The staff reviewed the following scopingand screening methodology implementation procedures:The staff reviewed the applicant's scoping and screening methodology implementationprocedures, including license renewal project guidelines (LRPGs), license renewal project documents/reports (LRPDs), AMR reports (e.g., AMRMs - mechanical, AMREs- electrical, and AMRCs - structural), as documented in the audit report, to ensure the guidance was consistent with the requirements of the Rule, NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants," Revision 1, (SRP-LR), and the Nuclear EnergyInstitute (NEI) 95-10, "Industry Guidelines for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule," Revision 6, (NEI 95-10).The staff found the overall process for implementing 10 CFR Part 54 requirements included inthe LRPGs, LRPDs, and AMRs was consistent with the Rule and industry guidance. The staff found guidance for identifying plant SSCs within the scope of the Rule, including guidelines for identifying SC component types within the scope of license renewal subject to an AMR, in the LRA, including in the implementation of NRC staff positions documented in NUREG-1800, and the information in requests for additional information (RAI) responses dated July 10, 2006. The review of these procedures focused on the consistency of the detailed procedural guidance with information in the LRA reflecting implementation of staff positions in the SRP-LR and interim staff guidance documents.After reviewing the LRA and supporting documentation, the staff finds LRA Section 2.1consistent with the scoping and screening methodology instructions. The applicant's methodology has sufficiently detailed guidance for the scoping and screening implementation process followed in the LRA.Sources of Current Licensing Basis Information. For VYNPS, system safety functions are statedin safety classification documents, the Maintenance Rule SSC basis documents for each system, and in design basis documents for systems for which DBDs were written. The staff considered the safety objectives in the UFSAR system descriptions and identified objectives meeting the safety-related Criterion of 10 CFR 54.4(a)(1) as system intended functions.The staff reviewed the scope and depth of the applicant's CLB information to verify whether theapplicant's methodology had identified all SSCs within the scope of license renewal as well as component types requiring AMRs. As defined in 10 CFR 54.3(a), the CLB applies NRC requirements, written licensee commitments for compliance with, and operation within, applicable NRC requirements, and plant-specific design bases docketed and in effect. The CLBincludes NRC regulations, orders, license conditions, exemptions, technical specifications,design-basis information in the most recent UFSAR, and licensee commitments in docketed correspondence like licensee responses to NRC bulletins, generic letters, and enforcementactions as well as commitments in NRC safety evaluations or licensee event reports.During the audit, the staff reviewed the applicant's information sources and samples of suchinformation, including the UFSAR, DBDs, controlled plant reference drawings, LRBDs, and Maintenance Rule information. In addition, the applicant's license renewal process identified 2-5additional potential sources of plant information pertinent to the scoping and screening process,including, licensing correspondence, the Fire Hazards Analysis, safety evaluations, and design documentation such as engineering calculations and design specifications. Additionally, theapplicant supplemented the review by using an electronic database developed during the plant FSAR accuracy verification project conducted between 1998 and 2000. The database contained approximately 10,000 documents including all correspondence in the public document room. The searchable database was available for query during the review of the CLB information in support of LRA development. The staff confirmed that the applicant's detailed license renewal program guidelines required use of the CLB source information developing scoping evaluations.
 
The VYNPS component database is the applicant's primary repository for component safety classification information. During the audit, the staff reviewed the applicant's administrative controls for VYNPS component database safety classification data. These controls are described and implementation is governed by plant administrative procedures. Based on a review of the administrative controls, and a sample of the VYNPS component database component safety classifications, the NRC staff concluded that the applicant had established adequate measures to control the integrity and reliability of VYNPS component database safety classification data, and therefore, the staff concluded that the VYNPS component database provided a sufficiently controlled source of component data to support scoping and screening evaluations.During the staff's review of the applicant's CLB evaluation process, the applicant provided thestaff with a discussion regarding the incorporation of updates to the CLB and the process used to ensure those updates are adequately incorporated into the license renewal process. The staff determined that LRA Section 2.1 provided a description of the CLB and related documents used during the scoping and screening process that is consistent with the guidance contained in NUREG-1800. In addition, the staff reviewed technical reports utilized to support identification of SSCs relied upon to demonstrate compliance with the safety-related criteria, nonsafety-related criteria, as well as the five regulated events referenced in 10 CFR 54.4(a)(1-3). The applicants license renewal program guidelines provided a comprehensive listing of documents used to support scoping and screening evaluations. The staff found these design documentation sources to be useful for ensuring that the initial scope of SSCs identified by the applicant was consistent with the plant's CLB.2.1.3.1.3  Conclusion Based on its review of LRA Section 2.1, the detailed scoping and screening implementationprocedures, and the results from the scoping and screening audit, the staff concludes that the applicant's scoping and screening methodology considers CLB information consistently with SRP-LR and NEI 95-10 guidance and, therefore, is acceptable.
2-62.1.3.2  Quality Controls Applied to LRA Development2.1.3.2.1  Staff Evaluation The staff reviewed the quality controls used by the applicant to ensure that scoping andscreening methodologies described in the LRA were adequately implemented. Although the applicant did not develop the LRA in accordance with a 10 CFR 50, Appendix B, QA program, the applicant utilized the following QA processes during the LRA development:
* Implementation of the scoping and screening methodology was governed by writtenprocedures.
* The applicant reviewed previous LRA NRC requests for additional information to ensurethat applicable issues were addressed in the LRA.
* The LRA was reviewed by the Offsite and Onsite Safety Review Committees prior tosubmittal to the NRC.
* The applicant performed an industry peer review of the LRA.
* The applicant's QA organization performed an independent review of the LRA. Thepurpose of this review was to ensure that the technical information used to develop the LRA was updated and approved in accordance with the station's QA program, and that industry peer and Offsite and Onsite Safety Review Committee issues were resolved and associated corrective actions implemented. 2.1.3.2.2  Conclusion Based on its review of pertinent LRA development guidance, discussion with the applicant'slicense renewal personnel, and review of the quality audit reports, the staff concludes that these QA activities add assurance that LRA development activities have been performed in accordance with the scoping and screening methodologies described in the LRA.2.1.3.3  Training2.1.3.3.1  Staff Evaluation The staff reviewed the applicant's training process for consistent and appropriate guidelinesand methodology for the scoping and screening activities and to ensure the guidelines and methodology were performed in a consistent and appropriate manner. The LRPGs provided the guidance and requirements for the training of the license renewalproject and site personnel. The training consisted of a combination of reading and attendingtraining sessions. The LRPGs specified the level of training which was required for the various groups participating in the development of the LRA and began with initial training, documented on a qualification card. The training was required for both the license renewal project personnel who prepared the application and for the site personnel who reviewed the application. In addition, license renewal refresher training was provided for the license renewal project and site personnel participating in the review. Refresher training included information on the license renewal process and information specific to the site. License renewal project and site personnel 2-7were required to review applicable license renewal regulations, NEI 95-10 and associatedprocedures. The applicant developed periodic production meetings in which the license renewal project personnel shared their knowledge and experience of a given subject with each other. The NRC staff reviewed completed qualification and training records of several of theapplicant's license renewal project personnel and also reviewed completed check lists. The staff found these records adequately documented the required training for the license renewal project personnel. Additionally, based on discussions with the applicant's license renewal project personnel during the audit, the NRC staff confirmed that the applicant's license renewal project personnel were knowledgeable on the license renewal process requirements and the specific technical issues within their areas of responsibility. On the basis of discussions with the applicant's license renewal project personnel responsiblefor the scoping and screening process, and a review of selected design documentation in support of the process, the NRC staff concluded that the applicant's license renewal project personnel understood the requirements of and adequately implemented the scoping and screening methodology established in the applicant's renewal application. The staff did not identify any concerns regarding the training of the applicant's license renewal project or site personnel.2.1.3.3.2  Conclusion Based on discussions with the applicant's license renewal personnel responsible for thescoping and screening process and review of selected documentation supporting the process, the staff concludes that the applicant's technical personnel understood the requirements and adequately implemented the scoping and screening methodology documented in the LRA. The staff concludes that the license renewal personnel were adequately trained and qualified for license renewal activities.2.1.3.4  Conclusion of Scoping and Screening Program Review Based on its review of LRA Section 2.1, review of the applicant's detailed scoping andscreening implementation procedures, discussions with the applicant's LRA personnel, and review of the scoping and screening audit results, the staff concludes that the applicant's scoping and screening program is consistent with SRP-LR guidance and, therefore, acceptable.2.1.4  Plant Systems, Structures, and Components Scoping MethodologyLRA Section 2.1, describes the methodology for scoping SSCs as required by 10 CFR 54.4(a)and the plant scoping process for systems and structures. Specifically, the scoping process consisted of developing a list of plant systems and structures and identifying their intended functions. Intended functions are those functions that are the basis for including a system or structure within the scope of license renewal as defined in 10 CFR 54.4(b) and are identified by comparing the system or structure function with the criteria in 10 CFR 54.4(a). The systems list was developed from the VYNPS component database and the structures list from a review of plant layout drawings and structure-specific system codes in the VYNPS component database.
2-8Finally, the applicant evaluated the components in the systems and structures that werein-scope of license renewal. The in-scope system boundary of SSCs subject to an AMR is depicted on the license renewal drawings. The applicant's scoping methodology, as described in the LRA, is discussed in the sections below.2.1.4.1  Application of the Scoping Criteria in 10 CFR 54.4(a)(1)2.1.4.1.1  Summary of Technical Information in the Application In LRA Section 2.1.1.1, "Application of Safety-Related Scoping Criteria," the applicant describedthe scoping methodology required by 10 CFR 54 as it relates to safety-related criteria in accordance with 10 CFR 54.4(a)(1). With respect to the safety-related criteria, the applicant stated that at VYNPS system safety functions are identified in safety classification documents, the maintenance rule SSC basis documents for each system, and in design basis documents (DBDs) for those systems for which a DBD was written. SSCs that are identified as safety-related in the UFSAR, in DBDs, or in the CRL were classified as satisfying criteria of 10 CFR 54.4(a)(1) and included within the scope of license renewal. The review also confirmed that all plant conditions, including conditions of normal operation, abnormal operational transients, design basis accidents, internal and external events, and natural phenomena for which the plant must be designed, were considered for license renewal scoping in accordance with 10 CFR 54.4(a)(1) criteria. The VYNPS CLB definition of safety-related SSCs is not identical to the definition provided inthe Rule. As a result, the applicant performed an evaluation of the differences between its CLB definition of safety-related and the Rule definition. 2.1.4.1.2  Staff Evaluation Pursuant to 10 CFR 54.4(a)(1), the applicant must consider all safety-related SSCs relied uponto remain functional during and following a design basis event (DBE) to ensure (a) the integrity of the reactor coolant pressure boundary, (b) the ability to shut down the reactor and maintain it in a safe shutdown condition, or (c) the ability to prevent or mitigate the consequences of accidents that could cause offsite exposures comparable to those of 10 CFR 50.34(a)(1),
10 CFR 50.67(b)(2), or 10 CFR 100.11.As to identification of DBEs, SRP-LR Section 2.1.3 states: The set of DBEs as defined in the Rule is not limited to Chapter 15 (orequivalent) of the UFSAR. Examples of DBEs that may not be described in this chapter include external events, such as floods, storms, earthquakes, tornadoes, or hurricanes, and internal events, such as a high-energy line break. Information regarding DBEs as defined in 10 CFR 50.49(b)(1) may be found in any chapter of the facility UFSAR, the Commission's regulations, NRC orders, exemptions, or license conditions within the CLB. These sources should also be reviewed to identify SSCs relied upon to remain functional during and following DBEs (as required by 10 CFR 50.49(b)(1)) to ensure the functions required by 10 CFR 54.4(a)(1).
2-9The staff's review of LRA Section 2.1 of VYNPS identified areas in which additional informationwas necessary to complete the review of the applicant's scoping and screening methodology.
The applicant responded to the staff's RAIs as discussed below. During the scoping and screening methodology audit, the staff questioned how non-accidentDBEs, particularly DBEs that may not be described in the UFSAR, were considered during scoping. The staff noted that limiting the review of DBEs to those described in the UFSAR accident analysis could result in omission of safety-related functions described in the CLB and requested the applicant provide a list of all DBEs that were evaluated as part of the license renewal review. However, during the audit, the staff was unable to identify such a list.
Therefore, in RAI 2.1-1, dated July 10, 2006, the staff requested that the applicant provide: a) a list of DBEs evaluated as part of the license renewal scoping process, b) describe the methodology used to ensure that all DBEs (including conditions of normal operation, anticipated operational occurrences, design-basis accidents, external events, and natural phenomena) were addressed during license renewal scoping evaluation, and c) a list of the documentation sources reviewed to ensure that all DBEs were identified. In its response, by letter dated August 10, 2006, the applicant described the DBEs evaluatedduring the license renewal effort and described the methodology used to ensure that all DBEs were addressed during license renewal scoping. Specifically, the applicant identified abnormal operational transients, design-basis accidents, events for which the alternate cooling system (ACS) is credited (i.e., loss of the Vernon Pond and flooding or fire in the service water (SW) intake structure), and additional DBEs such as external and internal flooding, earthquakes, tornadoes and natural phenomena as constituting the DBEs for the Vermont Yankee plant.In addition, the applicant described two basic means of ensuring that all of the plant DBEs wereaddressed during the license renewal scoping process. These include: (1) reviewing the UFSAR and DBDs (i.e., for external and internal events and safety analyses) directly for the identification of the DBEs and subsequently for the identification of the SSCs credited for each event, and (2) reviewing and evaluating the safety classification of systems and components as governed by the plant safety classification process. This process ensures that site-specific procedures, design basis information, regulatory commitments, and regulatory guidance are considered during the classification process. The VYNPS safety classification process identifiesthose SSCs which are credited for performance of the intended safety functions in accordance with 10 CFR 54.4(a)(1). The NRC staff reviewed a sample of the DBDs identified as sources of this information. Thestaff found the DBDs to contain a detailed evaluation of events, and included appropriate CLB documentation references to support the review and a resultant matrix of systems and structures relied upon to remain functional during and following these DBEs. The staff concluded that the applicant considered DBEs consistent with the guidance contained inNUREG-1800.The staff reviewed the additional information provided by the applicant and, on the basis ofproviding (1) a detailed listing of the DBEs for the plant; (2) a description of the design and configuration control processes used to identify the SSCs credited for DBE mitigation; and (3) a 2-10description of the processes and sources of DBE information used to perform the scopingevaluation consistent with the requirements of 10 CFR 54.4(a)(1), the staff found that the applicant has adequately addressed the staff's RAI. Therefore, the staff's concern described in RAI 2.1-1 is resolved.The applicant performed scoping of SSCs for the 10 CFR 54.4(a)(1) criterion in accordancewith the LRPGs which provided guidance for the preparation, review, verification, and approval of the scoping evaluations to assure the adequacy of the results of the scoping process. The staff reviewed these guidance documents governing the applicant's evaluation of safety-related SSCs, and sampled the applicant's scoping results reports to ensure the methodology was implemented in accordance with those written instructions. In addition, the staff discussed the methodology and results with the applicant's technical personnel who were responsible for these evaluations. The staff reviewed a sample of the license renewal scoping results for the CSS and the IntakeStructure to provide additional assurance that the applicant adequately implemented their scoping methodology with respect to 10 CFR 54.4(a)(1). The staff confirmed that the scoping results for each of the sampled systems were developed consistent with the methodology, the SSCs credited for performing intended functions were identified, and the basis for the results as well as the intended functions were adequately described. The staff confirmed that the applicant had identified and used pertinent engineering and licensing information to identify the SSCs required to be in-scope in accordance with the 10 CFR 54.4(a)(1) criteria.To help document the identification of SSCs in-scope in accordance with the 10 CFR 54.4(a)criteria, the applicant developed a license renewal information system (LRIS) which contained detailed design description information about each plant system and structure and the relevant functions of those systems and structures. A list of safety-related SCs was initially identified by using the existing components list in the VYNPS component database. The VYNPS component database safety-classification field was reviewed to ensure that any system or structure that has a component identified as safety-related was considered for inclusion into the scope of the license renewal project. For VYNPS, component safety classification fields SC1 - SC3 corresponded to the 10 CFR 54.4(a)(1) criteria. Additionally, the SC1 database safety-classification and associated plant system drawings provided a starting point for identifying specific components which were required to meet the 10 CFR 54.4(a)(1) criteria. During the audit, the applicant described the process used to evaluate components classifiedas safety-related that did not perform a safety-related intended function. As part of the process, the applicant stated that the safety-classification of several components were reevaluated in order to reconcile differences between scoping determinations and facility database information or CLB information. Those components that were identified as safety-related that did not perform an intended function were explicitly evaluated and described in the LRPD's and the rationale for their exclusion from scope of the license renewal was documented. For instances where components identified as safety-related in the VYNPS component database did not perform any safety-related functions, the applicant identified these components and performed additional evaluations to confirm that the component did not perform or were not credited in the CLB for any specific safety-related functions. Examples included the reactor water cleanup (RWCU) system and the augmented off-gas (AOG) system.
2-11The staff reviewed the safety classification criteria used to determine the safety classification toverify consistency between the VYNPS CLB definition and the Rule definition in 10 CFR 54.4(a). In addition, the staff reviewed the applicant's evaluation of the differences between the Rule definition and the site-specific definition of safety-related to ensure all potential SSCs meeting the requirements of 10 CFR 54.4(a)(1) were adequately addressed.
The applicant documented this evaluation in the LRA and LRPDs. As part of the license renewal development activities, the applicant stated that the site-specific definition for safety-related was nearly identical to the Rule definition with the following exception:The CLB definition regarding potential offsite exposure limits refers to10 CFR 50.67 whereas the Rule also references comparable guidelines in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), and 10 CFR Part 100 respectively.During the audit, the staff reviewed the applicant's evaluation of the Rule and VY CLBdefinitions pertaining to 10 CFR 54.4(a)(1). Based on this review, the staff confirmed that 10 CFR 50.34(a)(1)(ii) is not applicable to VYNPS as it concerns applicants for a constructionpermit who apply on or after January 10, 1997. In addition, the staff has amended the VYNPS operating license to allow use of an alternative source term for accident analyses in accordance with 10 CFR 50.67. The change to 10 CFR 50.67 dose limits does not affect the VYNPS safety classification definition. The accident analyses with the alternative source term credits additionalfunctions for the standby liquid control (SLC) and residual heat removal (RHR) systems: (1) the SLC system is credited with maintaining pH in the torus to prevent re-evolution of iodine, and (2) the drywell spray function of the RHR system is credited with particulate removal. The staff confirmed that these intended functions were included in the scoping evaluation.During the audit, the staff also confirmed that any SSCs specifically credited for the10 CFR 50.67(b) leakage pathway, were identified and included in-scope. For VYNPS, the main condenser and main steam (MS) bypass leakage pathway are credited for 10 CFR 50.67(b) leakage pathway and meet the 10 CFR 54.4(a)(1)(iii) criterion for inclusion in-scope. The staff confirmed that these pertinent SSCs were appropriately identified and placed in-scope. Since the specific SSCs were classified as nonsafety-related in the plant component database, they were placed in-scope in accordance with 10 CFR 54.4(a)(2) for nonsafety-related potentially affecting a safety-related functions.The staff reviewed the evaluation and discussed the results of the evaluation with theapplicant's license renewal team members. The staff determined that the differences between the VYNPS safety-related definition and the Rule definition were adequately identified and evaluated. These differences did not result in any additional components being considered safety-related beyond those identified in the VYNPS CLB.2.1.4.1.3  Conclusion Based on this sample review, discussions with the applicant, and review of the applicant'sscoping process, the staff finds that the applicant's methodology for identifying systems and structures meets 10 CFR 54.4(a)(1) scoping criteria and, therefore, is acceptable.
2-122.1.4.2  Application of the Scoping Criteria in 10 CFR 54.4(a)(2) 2.1.4.2.1  Summary of Technical Information in the Application In LRA Section 2.1.1.2, "Application of Criterion for Nonsafety-Related SSCs Whose FailureCould Prevent the Accomplishment of Safety Functions," and Section 2.3.3.13, "Miscellaneous Systems in-Scope for (a)(2)," the applicant described the scoping methodology as it related to the nonsafety-related criteria in accordance with 10 CFR 54.4(a)(2). The applicant evaluated the SSCs that met 10 CFR 54.4(a)(2) using three categories: (1)Nonsafety-Related SSCs Required to Perform a Function that Supports aSafety-Related SSCThe SSCs required to perform a function in support of safety-related components wereclassified as safety-related and included in the scope of license renewal in accordance with 10 CFR 54.4(a)(1). The applicant reviewed engineering and licensing documents (UFSAR, Maintenance Rule scoping documents, and DBDs) to identify exceptions which were included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2).(2)Nonsafety-Related SSCs Connected to Safety-Related SSCsThe applicant identified certain nonsafety-related components and piping outside of thesafety-class pressure boundary which must be structurally sound in order to maintain the pressure boundary integrity of safety-related piping. These components perform a structural support function.For piping in this structural boundary, pressure integrity is not required (except when requiredfor spatial interaction between nonsafety-related and safety-related SSCs); however, piping within the safety class pressure boundary depends on the structural boundary piping and supports in order for the system to fulfill its safety function. For VYNPS, the "structural boundary" is defined as the portion of a piping system outside the safety class pressure boundary, yet relied upon to provide structural support for the pressure boundary. The structural boundary is often shown on piping isometric drawings and was considered synonymous with the first seismic or equivalent anchor. Nonsafety-related piping systems connected to safety-related systems were included up to the structural boundary or to a point that includes an adequate portion of the nonsafety-related piping run to conservatively include the first seismic or equivalent anchor. An equivalent anchor was a combination of hardware or structures that together are equivalent to a seismic anchor. A seismic anchor was defined as hardware or structures that, as required by the analysis, physically restrain forces and moments in three orthogonal directions. The physical arrangement as analyzed insures that the stresses that are developed in the safety-related piping and supports are within the applicable piping and structural code acceptance limits. If isometric drawings were not readily available to identify the structural boundary, connected lines were included to a point beyond the safety-related/nonsafety-related interface, such as a base-mounted component, flexible connection, or the end of a piping run (such as a drain line). The LRA stated that the approach was consistent with the guidance in NEI 95-10, Appendix F.
2-13(3)Nonsafety-related SSCs with a Potential for Spatial Interaction with Safety-Related SSCsThe applicant considered physical impact, and fluid leakage, spray or flooding when evaluatingthe potential for spatial interaction between nonsafety-related systems and safety-related SSCs.
The applicant used a spaces approach for scoping of nonsafety-related systems with potential spatial interaction with safety-related SSCs. The spaces approach focused on the interaction between nonsafety-related and safety-related SSCs that are located in the same space. A "space" was defined as a room or cubicle that is separated from other spaces by substantial objects (such as wall, floors, and ceilings). The space was defined such that any potential interaction between nonsafety-related and safety-related SSCs is limited to the space.Physical Impact or FloodingThe applicant evaluated missiles which could be generated from internal or external eventssuch as failure of rotating equipment. Inherent nonsafety-related features that protect safety-related equipment from missiles; overhead-handling systems whose structural failure could result in damage to any system that could prevent the accomplishment of a safety function; and walls, curbs, dikes, doors, etc, that provide flood barriers to safety-related SSCs meet the criteria of 10 CFR 54.4(a)(2). Nonsafety-related equipment that was determined to have a possible impact on safety-related SSCs were included within the scope of license renewal.The applicant evaluated nonsafety-related portions of high-energy lines, including review of theUFSAR and relevant topical design basis document. The applicant's high-energy systems were evaluated to ensure identification of components that are part of nonsafety-related high-energy lines that can effect safety-related equipment. If the applicant's high-energy line break (HELB) analysis assumed that an nonsafety-related piping system did not fail or assumed failure only at specific locations, then that piping system (piping, equipment and supports) is included within the scope of license renewal.Fluid Leakage or SprayThe applicant evaluated moderate and low energy systems which have the potential for spatialinteractions of spray and leakage. Nonsafety-related systems and nonsafety-related portions of safety-related systems with the potential for spray or leakage that could prevent safety-related SSCs from performing their required safety function were considered in the scope of license renewal. In addition, the nonsafety-related supports for nonsafety-related piping systems with a potential for spatial interaction with safety-related SSCs were included in the scope of license renewal.The applicant determined that operating experience indicated that nonsafety-relatedcomponents containing only air or gas have experienced no failures due to aging that could impact the ability of safety-related equipment to perform required safety functions. There are no effects of aging requiring management for these components when the environment is a dry gas. Systems containing only air or gas were not included in the scope of license renewal.
2-14Protective features, such as whip restraints, spray shields, supports, missile or flood barriers,(which can be applicable preventing physical impact and fluid leakage, spray, or flooding) were installed to protect safety-related SSCs against spatial interaction with nonsafety-related SSCs.
Such protective features credited in the plant design were included within the scope of license renewal.2.1.4.2.2  Staff Evaluation Pursuant to 10 CFR 54(a)(2), the applicant must consider all nonsafety-related SSCs, thefailure of which could prevent satisfactory performance of safety-related SSCs relied upon to remain functional during and following a DBE to ensure (a) the integrity of the reactor coolant pressure boundary, (b) the ability to shut down the reactor and maintain it in a safe shutdown condition, or (c) the ability to prevent or mitigate the consequences of accidents that could cause offsite exposures comparable to those of 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11, as applicable.NRC Regulatory Guide (RG) 1.188, Revision 1, "Standard Format and Content for Applicationsto Renew Nuclear Power Plant Operating Licenses," dated September  2005, endorses the use of NEI 95-10, Revision 6, for methods the staff considers acceptable for compliance with 10 CFR Part 54 in preparing LRAs. NEI 95-10, Revision 6, addresses the staff positions on 10 CFR 54.4(a)(2) scoping criteria, nonsafety-related SSCs typically identified in the CLB, consideration of missiles, cranes, flooding, high-energy line breaks, nonsafety-related SSCs connected to safety-related SSCs, nonsafety-related SSCs in proximity of safety-related SSCs, and the mitigative and preventive options in nonsafety-related and safety-related SSCs interactions.The staff states that applicants should not consider hypothetical failures but rather base theirevaluation on the plant's CLB, engineering judgement and analyses, and relevant operating experience, describing operating experience as all documented plant-specific and industry-wide experience useful in determining the plausibility of a failure. Documentation would include NRC generic communications and event reports, plant-specific condition reports, such industry reports as safety operational event reports, and engineering evaluations.The staff reviewed LRA Section 2.1.1.2, "Application of Criterion for Nonsafety-Related SSCsWhose Failure Could Prevent the Accomplishment of Safety Functions," and Section 2.3.3.13, "Miscellaneous Systems in-Scope for (a)(2)." The applicant described the scoping methodology as it related to the nonsafety-related criteria in accordance with 10 CFR 54.4(a)(2). The applicant evaluated 10 CFR 54.4(a)(2) SSCs with the three categories from the NRCguidance to the industry on identification and treatment of such SSCs:Nonsafety-Related SSCs Required to Perform Functions that Support a Safety-Related SSCsNonsafety-related SSCs required to perform a function in order to support a safety-relatedfunction had been previously classified as safety-related and were identified as such in the equipment data base. Therefore the nonsafety-related SSCs required to perform a function to support a safety-related function had been included in the scope of license renewal as safety-related as required by 10 CFR 54.4(a)(1). This evaluating criteria was discussed in the 2-15applicant's 10 CFR 54.4(a)(2) project report. The single exception to this approach was themain condenser and main steam isolation valve (MSIV) leakage pathway which was classified as an nonsafety-related system and was required to perform a function to support a safety-related function. This system was included in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The staff found that the applicant implemented an acceptable method for scoping of nonsafety-related systems that perform a function that supports a safety-related intended function.Nonsafety-Related SSCs Connected to Safety-Related SSCsThe applicant had previously performed an analysis to identify the nonsafety-related SSCs,outside of the safety-related pressure boundary, which were required to be structurally sound in order to maintain the integrity of the safety-related SSCs. This collection of nonsafety-related and safety-related SSCs was identified as the "structural boundary" and was typically identified on the plant isometric drawings. The applicant had included all nonsafety-related SSCs within the analyzed structural boundary in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The LRA states that if the structural boundary was not indicated on the applicable isometric drawings, the applicant had identified the portion of the nonsafety-related SSCs beyond the safety-related SSCs to the first equivalent anchor or seismic anchor and included this portion of the nonsafety-related SSCs within the scope of license renewal. The term equivalent anchor was defined in the LRA as a combination of hardware or structures that together are equivalent to a seismic anchor (a seismic anchor was defined as hardware or structures that, as required by analysis, physically restrain forces and moments in three orthogonal directions). The LRA also indicated that if the structural boundary could not beidentified for the applicable nonsafety-related/safety-related interface, the nonsafety-related SSCs were included to a point beyond the nonsafety-related/safety-related interface to a base-mounted component, flexible connection, or to the end of the piping run in accordance with the guidance of NEI 95-10. NEI 95-10, Appendix  F describes the use of "bounding criteria" as a method of determining the portion of nonsafety-related SSCs to be included within the scope of license renewal.The staff was unable to determine whether equivalent anchors (such as a combination ofsupports in the three orthogonal directions) had been used, in addition to the bounding criteria (base-mounted component, flexible connection, or the end of the piping run) discussed in the LRA and the 10 CFR 54.4(a)(2) project report which described the AMR of nonsafety-related systems and components affecting safety-related systems. In RAI 2.1-2, dated July 10, 2006, the staff requested that the applicant provide information related to the method used to develop the structural boundary and whether equivalent anchors had been used in addition to the bounding criteria discussed in the LRA. In its response, by letters dated August 10, 2006, October 17, 2006, and July 3, 2007 theapplicant further described the process used to determine the structural boundaries for those nonsafety-related systems which provided limited structural support to safety-related systems.
As part of the applicant's evaluation, isometric drawings of plant piping systems were reviewed where applicable to determine the location of structural boundaries. These isometric drawings were developed as part of the plant design process utilizing the results of piping stress analyses. No new analyses or isometric drawings were developed to support the license renewal process. Rather, the existing drawings and analyses were used to develop the 2-16structural boundaries, and in those instances where isometric drawings were not readilyavailable, the applicant used the bounding criteria in NEI 95-10 to identify the portions of the nonsafety-related system necessary to support the intended function. With respect to the use of equivalent anchors, the applicant stated that other than the actual structural boundaries identified as a result of the existing piping stress analysis, isometric drawings, and use of the bounding criteria, they did not use any equivalent anchors to identify the structural boundaries for the nonsafety-related systems identified as performing a 10 CFR 54.4(a)(2) function.The staff reviewed the additional information provided by the applicant and found that theapplicant has adequately addressed the staff's RAI, based on the detailed description of the process used to identify the structural boundaries, and confirmation that equivalent anchors were not used for the purposes of identifying structural boundaries for the nonsafety-related systems identified as performing a 10 CFR 54.4(a)(2) function, the staff. Therefore, the staff's concern described in RAI 2.1-2 is resolved. Nonsafety-Related SSCs with a Potential for Spatial Interation with Safety-Related SSCsThe applicant considered physical impact, and fluid leakage, spray or flooding when evaluatingthe potential for spatial interaction between nonsafety-related systems and safety-related SSCs.
The applicant used a spaces approach for scoping of nonsafety-related systems with potential spatial interaction with safety-related SSCs. The spaces approach focused on the interaction between nonsafety-related and safety-related SSCs that are located in the same space. A "space" was defined as a room or cubicle that is separated from other spaces by substantial objects (such as wall, floors, and ceilings). The space was defined such that any potential interaction between nonsafety-related and safety-related SSCs is limited to the space.The 10 CFR 54.4(a)(2) project report stated that the applicant had evaluated situations wheremissiles could be generated from internal or external events such as failure of rotating equipment. The nonsafety-related design features that protect safety-related SSCs from such missiles are within the scope of license renewal. In addition, the 10 CFR 54.4(a)(2) project report stated that the applicant had evaluated overhead-handling systems to identify those whose structural failure could result in damage to any system that could prevent the accomplishment of a safety function. Nonsafety-related overhead-handling equipment determined to have a possible impact on safety-related SSCs were included within the scope of license renewal.The LRA stated that the applicant had evaluated nonsafety-related portions of high-energylines, including review of the UFSAR and relevant topical design basis document. As discussed in the 10 CFR 54.4(a)(2) project report, the applicant used these references to evaluate the high-energy lines for postulated pipe breaks and identified eleven systems within the reactor building and five systems outside the reactor building. The applicant's high-energy systems were evaluated to ensure identification of components that are part of nonsafety-related high-energy lines that can effect safety-related equipment. If the applicant's high-energy line break (HELB) analysis assumed that a nonsafety-related piping system did not fail, or assumed failure only at specific locations, then that piping system (piping, equipment and supports) was included in the scope of license renewal. Many of the identified systems were safety-related and 2-17included within the scope of license renewal in accordance with 10 CFR 54.4(a)(1). Theremaining nonsafety-related high-energy lines that were determined to have potential interaction with safety-related SSCs were included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2).The applicant evaluated moderate and low energy systems that have the potential for spatialinteractions of spray and leakage. Nonsafety-related systems and nonsafety-related portions of safety-related systems with the potential for spray or leakage that could prevent safety-related SSCs from performing their required safety function were considered in the scope of license renewal. In addition, the applicant evaluated retired in place (RIP) systems for potential for spatial interaction. These RIP systems include both air-filled and fluid-filled portions of systems which were depressurized and isolated or capped from the remaining system. The applicant performed a review of the material/environment combinations for the RIP systems to determine if leakage of any fluid-filled portions due to corrosion could create the potential for a spatial interaction. The applicant applied the guidance from the Electric Power Research Institute (EPRI), "Non-Class 1 Mechanical Implementation guideline and Mechanical Tools,"
Revision 4, 2006. Consistent with the EPRI tools guidance, the applicant determined that the current configuration of these systems would not provide the necessary mechanisms to cause a failure in these systems which could result in system degradation and the potential subsequent leakage.The 10 CFR 54.4(a)(2) project report stated that the applicant used a "spaces" approach toidentify the nonsafety-related SSCs which were located within the same space as safety-related SSCs. A space was defined as a room or cubicle, separated by walls, floors, and ceilings. The applicant documented the review of each mechanical system for potential spatial interaction with safety-related SSCs in applicant's scoping results report, as documented in the audit report. Following identification of the applicable mechanical systems, the applicant reviewed the system functions to determine whether the system contained fluid, air or gas. Nonsafety-related SSCs containing air or gas were excluded from the scope of license renewal. The applicant then reviewed the mechanical systems to determine whether the system had any components located within a safety-related structure. Those liquid-filled systems determined to have components located within a safety-related structure where then reviewed to determine if the system had components located within a space containing safety-related SSCs. Those nonsafety-related SSCs determined to contain fluid and to be located within a space containing safety-related SSCs were included within the scope license renewal. In its letter dated July 3, 2007, the applicant included addition information in response toRAI 2.1-2 (which discussed nonsafety-related piping attached to safety-related SSCs). As a result of the staff's inspection activities, the applicant expanded its review of nonsafety-related SSCs located in the turbine building and the potential for spatial interaction with safety-related SSCs. The applicant identified that portions of certain systems within the scop of license renewal had been expanded to include additional nonsafety-related components located in the turbine building. These components are within the scope of license renewal due to the potential for spatial interaction with safety-related SSCs and are subject to an aging management review.
2-18In addition, protective features, such as whip restraints, spray shields, supports, missile or floodbarriers (which can prevent physical impact and fluid leakage, spray, or flooding), installed to protect safety-related SSCs against spatial interaction with nonsafety-related SSCs were included within the scope of license renewal.2.1.4.2.3  Conclusion Based on its review, the staff determines that the applicant's methodology for identifyingsystems and structures meets 10 CFR 54.4(a)(2) scoping criteria and, therefore, is acceptable.
This determination is based on a review of sample systems, discussions with the applicant, and review of the applicant's scoping process.2.1.4.3  Application of the Scoping Criteria in 10 CFR 54.4(a)(3) 2.1.4.3.1  Summary of Technical Information in the Application In LRA Section 2.1.1.3, "Application of Criterion for Regulated Events," the applicant describedthe methodology for identifying systems, structures, and components relied on in safety analyses or plant evaluation to perform a function. Mechanical systems and structures that perform a intended function that demonstrates compliance with the regulations for fire protection (10 CFR 50.48), environmental qualification (10 CFR 50.49), pressurized thermal shock (10 CFR 50.61), anticipated transients without scram (ATWS) (10 CFR 50.62), and station blackout (SBO) (10 CFR 50.63) were included in the scope of license renewal.
Mechanical systems and structures that have an intended function for 10 CFR 54.4(a)(3) are identified in LRA Sections 2.3 and 2.4. For example, LRA Section 2.3.2.2 states that the core spray (CS) system has two intended functions for 10 CFR 54.4(a)(3): the Appendix R safe shutdown capability analysis and the SBO coping analysis. LRA Section 2.4.3 states that the intake structure has one intended function for 10 CFR 54.4(a)(3): the Appendix R safe shutdown capability analysis for fire protection. All plant electrical and instrumental and control (EIC) systems and electrical equipment in mechanical systems were included in-scope of license renewal.Fire Protection. The applicant described the scoping of mechanical systems and structuresrequired to demonstrate compliance with the fire protection requirements in LRA Section 2.1.1.3.1, "Commission's Regulations for Fire Protection (10 CFR 50.48)." The applicant reviewed its CLB and identified the mechanical systems and structures relied upon to meet Appendix  R and 10 CFR 50.48 requirements. Mechanical systems and structures credited with fire prevention, detection, mitigation in areas containing equipment important to safe operation of the plant, and equipment credited with safe shutdown in the event of a fire were included in-scope license renewal.Environmental Qualification. The applicant described the environmental qualificationrequirements of 10 CFR 50.49 in LRA Section 2.1.1.3.2, "Commission's Regulations for Environmental Qualification (10 CFR 50.49)." All plant EIC systems and electrical equipment in mechanical systems were included in-scope of license renewal. Pressurized Thermal Shock. These requirements are not applicable because Vermont Yankeeis a Boiling Water Reactor.
2-19Anticipated Transient Without Scram. The applicant described the scoping of mechanicalsystems and structures required to demonstrate compliance with the anticipated transient without scram (ATWS) requirements of 10 CFR 50.62 in LRA Section 2.1.1.3.4, "Commission's Regulations for Anticipated Transients without Scram (10 CFR 50.62)." Mechanical systems and structures that perform a 10 CFR 50.62 intended function were included in-scope of license renewal. Station Blackout. The applicant described the scoping criteria in LRA Section 2.1.1.3.5,"Commission's Regulations for Station Blackout (10 CFR 50.63)." The applicants licensing basis requires a SBO coping duration of two hours and mechanical systems and structures required to support the two-hour coping duration are within the scope of license renewal.
Although the switchyard is not considered a plant system, the offsite power system and related structures required to restore offsite power were also included in-scope of license renewal.2.1.4.3.2  Staff Evaluation The staff reviewed the applicant's approach to identifying mechanical systems and structuresrelied upon to perform a function related to the four regulated events applicable to boiling water reactors (BWRs) required by 10 CFR 54.4(a)(3). As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the review, and evaluated a sample of the resultant mechanical systems and structures identified as in-scope for 10 CFR 54.4(a)(3) criteria. The LRPGs described the applicant's process for identifying systems and structures that are inthe scope of license renewal. The LRPGs stated that all mechanical systems and structures that perform an intended function for 10 CFR 54.4(a)(3) are to be included in-scope of license renewal, and that the results of scoping are documented in the applicants scoping results report. The report also described the procedures and data base that were used to identify mechanical systems and structures for regulated events. In addition, the applicant used a variety of The Topical Design Basis Documents, as described in the audit report, to identify the principle systems for each regulated event. The applicants component database uses a classification code of "OQA" for components that are not safety-related but are subject to the requirements imposed by NRC regulations. Systems initially identified as not meeting the criterion of 10 CFR 54.4(a)(3) based on review of design basis information were reviewed for OQA components in the component database to verify that the systems performed no intended functions for license renewal regulated events. Fire Protection. The applicant's LRPDs state that the Fire Hazard Analysis, Fire Protection and Appendix R Program, and Safe Shutdown Capability Analysis, are used to identify mechanical systems and structures that are in-scope of license renewal. The report identifies the mechanical systems that are included in-scope of license renewal because they perform a 10 CFR 50.48 intended function. For example, the fire protection system has one intended function, which is to extinguish fires in the vital areas of the plant. The LRPDs summarizes the scoping results for mechanical systems and identifies 23 mechanical systems which have one 2-20or more 10 CFR 50.48 intended functions. The report also identifies the structures that areincluded in-scope of license renewal because they perform a 10 CFR 50.48 function, and provides a summary of the scoping results for ten structures that have one or more 10 CFR 50.48 intended functions. For example, the carbon dioxide (CO
: 2) tank foundation hasone intended function, which is to provide support for the CO 2 tank. Environmental Qualification. For the environmental qualification regulated event, the staffreviewed the LRA, the applicant's implementation procedures, results reports, and the master equipment list. These were used by the applicant to identify environmental qualification components within the scope of license renewal. The staff also reviewed the environmental qualification list which was used by the applicant during the screening process to identify short-lived components.Anticipated Transient Without Scram. The applicant's scoping results report identifies themechanical systems that are included in-scope of license renewal because they perform a 10 CFR 50.62 intended function. For example, one intended function of the control rod drive (CRD) system is to provide alternate rod insertion during an ATWS event. The report summarizes the scoping results for mechanical systems, identifies that the CRD and SLC systems perform 10 CFR 50.62 intended functions, and identifies one structure that is included in-scope of license renewal because it performs a 10 CFR 50.62 intended function. A criterion for including the reactor building in-scope of licensee renewal was that it housed equipment credited for ATWS. Station Blackout. The applicant's scoping results report states that mechanical systems andstructures credited with the two-hour coping duration and switchyard components required to restore offsite power are included in-scope of license renewal. The report identifies the mechanical systems that are were included in-scope of license renewal because they perform a 10 CFR 50.63 intended function. For example, the CS system has one intended function which is to provide reactor coolant makeup in the SBO coping analysis. The report summarizes the scoping results for mechanical systems, identifies eight mechanical systems that have one or more 10 CFR 50.63 intended functions, and identifies that the Offsite Power system is in-scope of license renewal because it performs a 10 CFR 50.63 intended function. The report also identifies the structures that were included in-scope of license renewal because they perform a 10 CFR 50.63 function. For example, the Vernon Hydroelectric Station (VHS) had one intended function which is to maintain integrity for SBO. The report summarizes the scoping results for structures and identifies five structures that have one or more 10 CFR 50.63 intended functions. Section 54.4(a)(3) of 10 CFR requires that all systems and structures relied on in safetyanalyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulation for SBO (10 CFR 50.63) be included in the scope of license renewal.
LRA Section 2.1.1.3.5 stated that the VHS is credited as the alternate alternating current (AC) power source for SBO. LRA Section 2.4.5 states that the VHS structures are in-scope of license renewal. LRA Section 2.3.5 and the applicant's scoping results report identify the VHS structures that are in the scope of license renewal. However, the VHS mechanical and electrical systems were not explicitly identified as being included in the scope of license renewal. It was not clear to the staff why the Vernon Station mechanical and electrical systems were not identified in the scope of license renewal in accordance with 10 CFR 54.4(a)(3). Therefore, the staff submitted RAI 2.1-3 requesting that the applicant describe the scoping and screening 2-21methodology as it applies to the mechanical and electrical systems associated with the VHS,and identify those mechanical and electrical systems and components (SCs) that are in the scope of license renewal and subject to an AMR. In its responses, by letters dated July 14, 2006, August 10, 2006, and October 20, 2006, theapplicant further described the scoping and screening process used to evaluate the VHS. The applicant identified the VHS as the alternate alternating current source credited for the VYNPS loss of all alternating current power compliance with 10 CFR 50.63 (SBO rule), and therefore, in-scope of license renewal. The applicant stated, in part, that they had credited the Federal Energy Regulatory Commission dam inspection program to manage the effects of aging on the civil and structural elements of the VHS. All additional mechanical and electrical systemsassociated with the turbine generator (TG) were considered an active assembly that is routinely confirmed through normal operation and therefore, consistent with the screening process, determined to not be subject to an AMR. Notwithstanding the screening of the mechanical and electrical systems as part of the active assembly, the applicant performed an IPA of the passive, long-lived electrical and mechanical components of the VHS. On the basis of this evaluation, the applicant identified specific structural, mechanical, and electrical SSCs thatsupport one or more of the intended functions of the VHS, which is consistent with the screening methodology described in Safety Evaluation (SE) Section 2.1.5.
 
The staff reviewed the applicant's responses to the RAI and concluded that the applicant has adequately described its process for scoping and screening of the VHS, and has identified the VHS as in-scope. The applicant has also evaluated the SSCs associated with the VHS, consistent with the screening methodology described in SE Section 2.1.5. The staff found that the applicant has adequately addressed the staff's RAI. Therefore, the staff's concern described in RAI 2.1-3 is resolved.
2.1.4.3.3  Conclusion On the basis of the sample review, discussions with the applicant, the applicants RAI response,and review of the applicant's scoping process, the NRC staff determines that the applicant's methodology for identifying systems and structures meets the scoping criteria of 10 CFR 54.4(a)(3), and is therefore acceptable.2.1.4.4  Plant-Level Scoping of Systems and Structures2.1.4.4.1  Summary of Technical Information in the Application System and Structure Level Scoping. The applicant documented its methodology for performingthe scoping of SSCs in accordance with 10 CFR 54.4(a) in its LRPGs and LRPDs. The applicant's approach to system and structure scoping provided in the site guidance was consistent with the methodology described in LRA Section 2.1. The LRPGs specify that the personnel performing license renewal scoping use CLB documents, describe the system or structure, and list the functions that the system or structure is required to accomplish. Sources of information regarding the CLB for systems included the UFSAR, DBDs, VYNPS component database, Maintenance Rule scoping reports, control drawings, and docketed correspondence.
The applicant then compared identified system or structures function lists to the scoping criteria to determine whether the functions met the scoping criteria of 10 CFR 54.4(a). The applicant 2-22documented the results of the plant-level scoping process in accordance with the LRPGs.These results were provided in the systems and structures LRPDs. The information in the LRPDs includes a description of the structure or system, a listing of functions performed by the system or structure, information pertaining to system realignment (as applicable), identification of intended functions, the 10 CFR 54.4(a) scoping criteria met by the system or structure, references, and the basis for the classification of the system or structure intended functions.
During the scoping methodology audit, the staff reviewed a sampling of LRPD reports and concluded that the applicant's scoping results in the LRPDs contained an appropriate level of detail to document the scoping process.
 
Conclusion On the basis of a review of the LRA, the scoping and screening implementation procedures,and a sampling review of system and structure scoping results during the methodology audit, the staff concludes that the applicant's scoping methodology for systems and structures was adequate. In particular, the staff determines that the applicant's methodology reasonably identified systems and structures within the scope of license renewal and their associated intended functions.Component Level Scoping. After the applicant identified the systems and structures within thescope of license renewal, a review of mechanical systems and structures was performed to determine the components in each in-scope system and structure. The structural and mechanical components that supported intended functions were considered within the scope of license renewal and screened to determine if an AMR was required. All electrical components within the mechanical and electrical systems were included in-scope as commodity groups (groups of like structures and components). The applicant considered three component classifications during this stage of the scoping methodology: mechanical, structural, and electrical. The VYNPS component database and controlled plant drawings provide a comprehensive listing of plant components. Component type and unique component identification numbers were used to identify each component identified as in-scope and subject to an AMR.Commodity Groups Scoping. Initially all electrical components within the mechanical andelectrical systems were included in the scope of license renewal as commodity groups. Since many electrical component types are considered active in accordance with the guidance in NEI 95-10 and the SRP-LR, they were screened out as not meeting the passive criteria and were subsequently not subject to an AMR. In LRA Section 2.1.2.3, the applicant described the commodity groups used to evaluate all in-scope electrical components subject to an AMR. Structural components were grouped as structural commodity types. Commodity types werebased on materials of construction. LRA Section 2.1.2.2.1 identified the various structural commodity groups including:
* steel
* threaded fasteners
* concrete
* fire barriers 2-23
* elastomers
* earthen structures
* flouropolymers and lubrite sliding surfacesInsulation. LRA Section 2.4.6, "Bulk Commodities," stated that insulation may have the specificintended functions of (1) controlling the heat load during design basis accidents in areas with safety-related equipment, or (2) maintaining integrity such that falling insulation does not damage safety-related equipment (reflective metallic type reactor vessel insulation). As such, insulation is included in the scope of license renewal as a commodity group in those applications where it provides one or both of the above intended function.Consumables. In LRA Section 2.1.2.4, "Consumables," the applicant discussed consumables.The guidance in Table 2.1-3 in NUREG-1800 was used to categorize and evaluate consumables. Consumables were divided into the following four categories for the purpose of license renewal: (a) packing, gaskets, component seals, and O-rings; (b) structural sealants; (c) oil, grease, and component filters; and (d) system filters, fire extinguishers, fire hoses, and air packs. The consumables in both categories (a) and (b) are considered as subcomponents. Category(a) subcomponents are not relied upon to form a pressure-retaining function and, therefore, not subject to an AMR. Category (b) subcomponents are structural sealants for structures within the scope of license renewal that require an AMR. Category (c) consumables are periodically replaced in accordance with plant procedures and, therefore, not subject to an AMR. Category (d) consumables are subject to replacement based on National Fire Protection Association (NFPA) standards in accordance with plant procedures and, therefore, not subject to an AMR.2.1.4.4.2  Staff Evaluation The staff reviewed the applicant's methodology for performing the scoping of plant systems andcomponents to ensure it was consistent with 10 CFR 54.4(a). The methodology used to determine the mechanical systems and components in-scope of license renewal was documented in LRPDs and plant level scoping results were identified in LRA Table 2.2-1. The scoping process defined the entire plant in terms of systems and structures. As specified in the LRPGs, the applicant identified the systems and structures that are subject to 10 CFR 54.4 review, described the processes for capturing the results of the review, and determined if the system or structure performed intended functions consistent with the criteria of 10 CFR 54.4(a).
The process was completed for all systems and structures to ensure that the entire plant was addressed. The applicant's technical personnel performed initial reviews on systems and structures identified in the CLB. The staff noted that a system or structure was presumed to be in-scope of license renewal if itperformed one or more safety-related functions or met the other scoping criteria per the Rule as determined by CLB review. Mechanical and structural component types that supported intended functions were considered in-scope of license renewal. All component types in electricalsystems in-scope of license renewal were considered in-scope of license renewal. These component types were placed in commodity groups. The electrical commodity groups were further screened to determine if they required an AMR. The staff did not identify any discrepancies with the methodology used by the applicant.
2-24The staff reviewed the methodology used by the applicant to generate commodity groups.Separate commodity groups were identified for various mechanical, structural, and electrical components and were identified in the LRPDs. The staff reviewed the commodity group level functions that were identified and evaluated by the applicant in accordance with 10 CFR 54.4(a). This process determined whether the commodity group was considered in-scope of license renewal.The staff found the methodology used acceptable.The staff reviewed the results of the scoping process documented in the LRPDs in accordancewith the LRPGs. This documentation included the description of the system or structure and the 10 CFR 54.4(a) scoping criteria met by the system or structure. The staff also reviewed a sample of the applicant's scoping documentation and concluded that it contained an appropriate level of detail to document the scoping process.The staff reviewed the applicant's evaluation of plant insulation as documented in the LRPDand the bulk commodities AMR. The applicant identified insulation as being in-scope and subject to an AMR based on it providing intended functions of insulating characteristics to reduce heat transfer, and structural or functional support to nonsafety-related SCs whose failure could prevent safety-related functions. Both mirror and non-mirror insulation were evaluated. The staff concludes that the applicant's methods and conclusions regarding insulation are acceptable.The staff reviewed the scoping and screening of consumables and finds that the applicantfollowed the process described in NUREG-1800, and appropriately identified and categorized the various consumables in accordance with the guidance. Plant consumables were initiallyidentified and evaluated to determine if any met the criteria requiring an AMR, such as structural sealants. Additionally, the applicant identified all pertinent industry guidelines whichwere used as the basis for replacement of the item, such as NFPA standards.2.1.4.4.3  Conclusion Based on its review of the LRA, scoping and screening implementation procedures, and asampling of system scoping results during the audit, the staff concludes that the applicant's scoping methodology for plant SSCs, commodity groups, insulation, and consumables is acceptable. In particular, the staff determines that the applicant's methodology reasonably identifies systems, structures, component types, and commodity groups within the scope of license renewal and their intended functions.2.1.4.5  Mechanical Component Scoping2.1.4.5.1  Summary of Technical Information in the Application In LRA Section 2.1, the applicant described the methodology for identifying mechanical systemcomponents that are in the scope of license renewal. For mechanical systems, the mechanical components that support the system intended functions are included in the scope of license renewal. For mechanical system scoping, a system was defined as the collection of components in the component database assigned to the system code. System intended functions were determined based on the functions performed by those components. Defining a system by the components in the database is generally consistent with the VYNPS 2-25maintenance rule scoping documents and safety classification procedure. Each mechanicalsystem was evaluated against the criteria of 10 CFR 54.4 to determine which system components performed the intended functions consistent with the scoping criteria. 2.1.4.5.2  Staff Evaluation The staff evaluated LRA Section 2.1 and the guidance in LRPDs, LRPGs, and aging management (AM) reports to complete the review of mechanical scoping process. The program guidelines and AM reports provided instructions for identifying and evaluating individual mechanical system components with respect to the scoping criteria. The CLB documents were utilized when determining whether a system or component is within the scope of 10 CFR 54.4(a). Examples of these sources included, but were not limited to, the UFSAR, Maintenance Rule database, separate ATWS, environmental qualification, fire protection and SBO documents, technical specifications, safety evaluation reports. Additional sources of mechanical component information included the VYNPS component database and individual system flow diagrams. Mechanical system diagrams were evaluated to create license renewal boundaries for eachsystem showing the in-scope components. Components that support a safety-related function or a regulated event were identified and further evaluated during the screening process to determine if the component should be subject to an AMR. Nonsafety-related components that are connected to safety-related components and provide structural support at the safety/nonsafety interface, or components whose failure could prevent satisfactory accomplishment of a safety-related function due to spatial interaction with safety-related SSCs are included in-scope and individually identified in the AMR associated with the 10 CFR 54.4(a)(2) evaluation, but were not specifically highlighted on the license renewal drawings. As part of the applicant's verification process, the list of mechanical components identified as in-scope were compared to the data in LRIS and the VYNPS component database to confirm the scope of components in the system. The staff reviewed the implementation guidance and the CLB documents associated withmechanical system scoping, and found that the guidance and CLB source information noted above were acceptable to identify mechanical components and support structures in mechanical systems that are within the scope of license renewal. The staff conducted detailed discussions with the applicant's license renewal project management personnel and reviewed documentation pertinent to the scoping process. The staff assessed whether the applicant had appropriately applied the scoping methodology outlined in the LRA and implementation procedures and whether the scoping results were consistent with CLB requirements. The staff determined that the applicant's proceduralized methodology was consistent with the description provided in the LRA Section 2.1 and the guidance contained in SRP-LR, Section 2.1, and wasadequately implemented.
2-26Scoping Methodology for the Core Spray System In LRA Section 2.3.2.2, "Core Spray," the applicant provided the scoping and screeningmethodology results for SSCs within the CS system. The CS system is a safety-related system and is credited with mitigating the effects of a loss of coolant events. The CS system accomplishes the following scoping criteria associated with the Rule:The CS system has the following intended functions for 10 CFR 54.4(a)(1):
* Provide injection of water following loss of reactor coolant
* Support primary containment isolation
* Provide reactor coolant pressure boundaryThe CS system has the following intended function for 10 CFR 54.4(a)(2):
* Maintain integrity of nonsafety-related components such that no physical interaction with safety-related components could prevent satisfactory accomplishment of a safety functionThe CS system has the following intended function for 10 CFR 54.4(a)(3):
* The CS system is credited in the Appendix R safe shutdown capability analysis (10 CFR50.48)
* The CS system is credited in the SBO coping analysis (10 CFR 50.63)The CS license renewal scoping boundary includes those portions of nonsafety-related pipingand equipment that extend beyond the safety-related/nonsafety-related interface. The scoping results indicated that the CS contains six system functions within the scope of license renewal. As part of the audit, The staff reviewed the applicant's methodology for identifying CSmechanical component type meeting the scoping criteria as defined in the Rule. The staff also reviewed the scoping methodology implementation procedures and discussed the methodology and results with the applicant. The staff confirmed that the applicant had identified and used pertinent engineering and licensing information in order to determine the CS mechanical component type required to be in-scope of license renewal. As part of the review process, the staff evaluated each system intended function identified for the CS system, the basis for inclusion of the intended function, and the process used to identify each of the system components credited with performing the intended function. The staff confirmed that the applicant had identified and highlighted system P&IDs to develop the system boundaries in accordance with the procedural guidance. The applicant was knowledgeable about the process and conventions for establishing boundaries as defined in the license renewal implementation procedures. Additionally, the staff confirmed that the applicant had independently confirmed the results in accordance with the governing procedures. Specifically, other license renewal personnel knowledgeable about the system had independently reviewed the marked-up drawings to ensure accurate identification of system intended functions. The applicant performed additional cross-discipline verification and independent reviews of the resultant highlighted drawings before final approval of the scoping effort.
2-272.1.4.5.3  ConclusionBased on its review of the LRA, scoping implementation procedures, and the system sampleand discussions with the applicant, the staff concludes that the applicant's methodology for identifying mechanical systems for 10 CFR 54.4(a) scoping criteria is acceptable.2.1.4.6  Structural Component Scoping2.1.4.6.1  Summary of Technical Information in the Application In LRA Section 2.1, the applicant described the methodology for identifying structures that arein the scope of license renewal. All plant structures and SBO-related non-plant structures were initially identified. Structure intended functions were identified using CLB documents such as the UFSAR, the Maintenance Rule document for buildings and structures, safety classification procedures, the fire hazards analysis, and the safe shutdown capability assessment. Structures that have an intended function for 10 CFR 54.4(a) were included in the scope of license renewal and listed in LRA Table 2.2-3. Structures that were not in-scope of license renewal are listed in LRA Table 2.2-4. LRA Section 2.4 describes the scoping results for the individualstructures that are in-scope of license renewal. For example, LRA Section 2.4.1 describes the intake structure's purpose and seismic classification. The intake structure was in-scope of license renewal because it provides supports, shelter and protection for safety and nonsafety-related systems within the scope of license renewal. 2.1.4.6.2  Staff Evaluation The staff reviewed the applicant's approach for identifying structures relied upon to perform thefunctions as required by 10 CFR 54.4(a). As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the review, and evaluated the scoping results for several structures that were identified in-scope of license renewal. The LRPGs describe the applicant's process for identifying structures that are in the scope oflicense renewal and state that all structures that perform an intended function are to be included in-scope of license renewal and that the scoping results are to be documented in the scoping results report. The scoping results report lists all the structures that were evaluated and also describes the procedures that were used to identify structures. In additional, the plant UFSAR, Maintenance Rule Document, Fire Hazards Analysis, and Safe Shutdown Capability Analysis were used to identify structures. The applicant's component database uses a classification code of "BLD" for structures, and a search of this data base was used to identify
 
structures. The staff reviewed the applicants implementation procedures and scoping results reports.Structural scoping was performed in a manner to ensure that all plant buildings, yard structures, and SBO related non-plant structures were considered. The scoping results report identified the intended functions for each structure required for compliance with one or more criteria of 10 CFR 54.4(a). The structural component intended functions were identified based on the guidance provided in NEI 95-10 and NUREG-1800. For structures, the evaluation boundaries were determined by developing a complete description of each structure with respect to the 2-28intended functions performed by the structure. The results of the review were documented inthe scoping results report (which contains a list of structures, evaluation results for each of the 10 CFR 54.4(a) criteria for each structure, a description of structural intended functions, and source reference information for the functions). The staff conducted detailed discussions with the applicant's license renewal team andreviewed documentation pertinent to the scoping process. The staff assessed if the scoping methodology outlined in the LRA and procedures were appropriately implemented and if the scoping results were consistent with CLB requirements. The staff also reviewed structural scoping evaluation results for the intake structure and VHS to verify proper implementation of the scoping process. Based on these audit activities, the staff did not identify any discrepancies between the methodology documented and the implementation results. 2.1.4.6.3  Conclusion Based on its review of the LRA, the applicant's detailed scoping implementation procedures,and a sampling of structural scoping results, the staff concludes that the applicant's methodology for identification of structural component types within the scope of license renewal meets 10 CFR 54.4(a) requirements and, therefore, is acceptable.2.1.4.7  Electrical Component Scoping2.1.4.7.1  Summary of Technical Information in the Application LRA Section 2.1.1, "Scoping Methodology" describes the scoping process associated withelectrical systems and components. For the purposes of system level scoping, plant EIC systems were included in the scope of license renewal. EIC components in mechanical systems were included in the evaluation of electrical systems. LRA Section 2.1.1 refers to LRASection 2.5, "Scoping and Screening Results: Electrical and Instrumentation and Control Systems," which further states that the default inclusion of plant electrical and instrumentation and controls (EIC) systems in the scope of license renewal reflects the method used for the scoping of electrical systems, which is different from the methods used for mechanical systems and structures. The approach used for EIC components was to include components in the review unless they were specifically screened out. When used with the plant spaces approach, this method eliminated the need for unique identification of every component and its specific location. This gave assurance that components were not excluded from an AMR.2.1.4.7.2  Staff Evaluation The staff evaluated LRA Sections 2.1.1 and 2.5 and the applicants implementing proceduresand aging management reports, as documented in the audit report, governing the electrical scoping methodology. The scoping phase for electrical components began with placing allelectrical components from plant systems within the scope of license renewal. In addition, any electrical components from non-plant systems that met the criteria for inclusion of 10 CFR 54.4(a) (such as components credited for SBO) were also included within the scope of license renewal. The staff determined that the data sources used for scoping included the EMPAC data base, the station single line drawing, and the cable design procurement specifications. The applicant gathered and sorted the collection of all electrical components 2-29from the data sources and assembled the data into word processing file, called the "scoping"file. The staff reviewed selected portions of the data sources and the resulting assemblage of the data contained in the "scoping" file. The staff selected components for validation. The applicant demonstrated the component location in the data source and how the component was included in the "scoping" file through implementation of the LRPGs.2.1.4.7.3  Conclusion Based on its review of the LRA, the applicant's detailed scoping implementation procedures,and a sampling of electrical scoping results, the staff concludes that the applicant's methodology for identification of electrical components within the scope of license renewal meets 10 CFR 54.4(a) requirements and, therefore, is acceptable.2.1.4.8  Conclusion for Scoping MethodologyBased on its review of the LRA and the scoping implementation procedures, the staffdetermines that the applicant's scoping methodology is consistent with SRP-LR guidance and has identified SSCs within the scope of license renewal as required by 10 CFR 54.4(a)(1),
(a)(2), and (a)(3). Therefore, the staff concludes that the applicant's methodology meets 10 CFR 54.4(a) requirements.2.1.5  Screening Methodology 2.1.5.1  General Screening MethodologyAfter identifying systems and structures within the scope of license renewal, the applicantimplemented a process for identifying SCs subject to an AMR in accordance with 10 CFR 54.21.2.1.5.1.1  Summary of Technical Information in the Application In LRA Section 2.1.2, "Screening Methodology," the applicant discussed the method ofidentifying components from in-scope systems and structures that are subject to an AMR. The screening process consisted of the following steps:Identification of components that are long-lived or passive for each in-scope mechanicalsystem, structure and electrical commodity group.Identification of the license renewal intended function(s) for all mechanical and structuralcomponent types and electrical commodity groups.Active components were screened out and therefore, did not require an AMR. The screeningprocess also identified short lived components and consumables. The short lived components are not subject to an AMR. Consumables are a special class of items that include packing, gaskets, component seals, O-rings, oil, grease, component filters, system filters, fire extinguishers, fire hoses, and air packs. Structural sealants for structures were the only consumables in-scope of license renewal that require an AMR.
2-302.1.5.1.2  Staff EvaluationPursuant to 10 CFR 54.21, the Commission requires that each LRA must contain an IPA thatidentifies SCs within the scope of license renewal that are subject to an AMR. The IPA must identify components that perform an intended function without moving parts or a change in configuration or properties (passive), as well as components that are not subject to periodic replacement based on a qualified life or specified time period (long-lived). The IPA includes a description and justification of the methodology used to determine the passive and long-lived SCs, and a demonstration that the effects of aging on those SCs will be adequately managed so that the intended function(s) will be maintained in accordance with all design conditions imposed by the plant-specific CLB for the period of extended operation.The staff reviewed the methodology used by the applicant to determine if mechanical andstructural component types, and electrical commodity groups in-scope of license renewal should be subject to an AMR. The applicant implemented a process for determining which SCs were subject to an AMR as required by 10 CFR 54.21(a)(1). In LRA Section 2.1.2, the applicant discussed these screening activities as they related to the component types and commodity groups within the scope of license renewal.The screening process evaluated these in-scope component types and commodity groups todetermine which ones were long-lived and passive and therefore, subject to an AMR. The staff reviewed LRA Sections 2.3, 2.4, and 2.5 that provided the results of the process used to identify component types and commodity groups subject to an AMR. The staff also reviewed the screening results reports for the CS system and intake structure.The applicant provided the staff with a detailed discussion of the processes used for eachdiscipline and provided administrative documentation that described the screening methodology. Specific methodology for mechanical, electrical, and structural is discussedbelow.2.1.5.1.3  Conclusion Based on its review of the LRA, the screening implementation procedures, and a sampling ofscreening results, the staff determines that the applicant's screening methodology is consistent with SRP-LR guidance and capable of identifying passive, long-lived components within the scope of license renewal and subject to an AMR. The staff determines that the applicant's process for identifying component types and commodity groups subject to an AMR meets 10 CFR 54.21 requirements and, therefore, is acceptable.2.1.5.2  Mechanical Component Screening2.1.5.2.1  Summary of Technical Information in the Application In LRA Section 2.1.2.1, "Screening of Mechanical Systems," the applicant discussed thescreening methodology for identifying passive and long-lived mechanical components and their support structures that are subject to an AMR. License renewal drawings were prepared to indicate portions of systems that support system intended functions within the scope of License renewal (with the exception of those systems in-scope for 10 CFR 54.4(a)(2) for physical 2-31interactions, as discussed below). In addition, the drawings identify components that are subjectto an AMR. Boundary flags are used in conjunction with safety-to-nonsafety class breaks to identify the system intended function boundaries. Boundary flags are noted on the drawings as system intended function boundaries. All components within these boundary flags and class breaks support system intended functions within the scope of license renewal. Components subject to an AMR (i.e., passive, long-lived components that support system intended functions) were highlighted to indicate that the component was subject to an AMR.2.1.5.2.2  Staff Evaluation The staff evaluated the mechanical screening methodology in LRA 2.1.2.1, "Screening ofMechanical Systems," the LRPDs, LRPGs, and the AMR reports, as documented in the audit report. The mechanical system screening process began with the results from the scoping process. The applicant reviewed each mechanical system flow diagram to identify passive and long-lived components. To identify system components required to perform a system intended function, the applicant generated a listing of mechanical system components based on information derived from controlled system diagrams and the VYNPS component database.
The LRPGs and LRPDs discuss in detail how to (1) determine system boundaries, (2) indicate components within a specific flow path which are required for performance of intended functions, and (3) determine and identify system and interdisciplinary interfaces (e.g.,
mechanical/structural, mechanical/electrical, structural/electrical). These components were entered into the LRIS database. The applicant also reviewed components in the VYNPS component database to confirm that all system components were considered. In cases where the mechanical system flow diagrams did not provide sufficient detail, such as large vendor supplied components (e.g., compressors, emergency diesel generators (EDGs)), the applicant reviewed associated component drawings or vendor manuals as necessary to identify individual components.The staff reviewed the results of the boundary evaluation and discussed the process furtherwith the applicant. The staff confirmed that mechanical system evaluation boundaries were established for each system within the scope of license renewal. These boundaries were determined by mapping the pressure boundary associated with system-level license renewal intended functions onto the controlled system drawings. Mechanical component types were loaded into a scoping and screening database and further review was performed to ensure all component types were identified. If a component type was not already in the LRIS, the component type was created for use in the license database. A preparer and an independent reviewer performed a comprehensive evaluation of the boundary drawings to ensure the completeness and accuracy of the review results. As part of the evaluation, the applicant also benchmarked passive and long-lived components for a system against previous LRAs containing similar systems.As part of the audit, the staff reviewed the methodology used by the applicant to identify SSCswhich met the screening criteria of the Rule. The staff confirmed that the applicant had implemented and followed the screening guidance in the SRP-LR and NEI 95-10. The staff confirmed the applicant had developed sufficiently detailed procedures for the screening of mechanical systems, had implemented those procedures, and had adequately documented the results in the associated AMR reports.
2-32Additionally, the staff reviewed the screening activities associated with the CS system. The staffreviewed the system intended functions and associated source documents identified for the system, the CS flow diagrams, and the associated results documented in the AMR report. The staff did not identify any discrepancies with the evaluation, and determined that the applicant has adequately followed the process documented in the LRPDs and adequately documented the results in the AMR reports.2.1.5.2.3  Conclusion Based on its review of the LRA, the screening implementation procedures, and a sample reviewof CS screening results, the staff determines that the applicant's mechanical component screening methodology is consistent with SRP-LR guidance. The staff concludes that the applicant's methodology for identification of passive, long-lived mechanical components within the scope of License renewal and subject to an AMR meets 10 CFR 54.21(a)(1) requirements.2.1.5.3  Structural Component Screening2.1.5.3.1  Summary of Technical Information in the Application The applicant described the methodology used for structural screening in LRA Sections 2.1.2.2,"Screening of Structures," and 2.4, "Scoping and Screening Results: Structures." LRA Section 2.1.2.2 states that structural components were evaluated to determine those subject to an AMR for each structure within the scope of license renewal. Specific structural components were identified from reviewing the CLB (drawings, etc.). Passive and long-lived structural components that performed an intended function were identified and subject to an AMR.
NUREG-1800 and NEI 95-10, Appendix B, were used as the basis for the identification of passive structural components. Structural components (door, gate, pipe support, strut, or siding for example) were categorized as steel, threaded fasteners, concrete, fire barriers, elastomers, earthen structures, or flouropolymers and lubrite sliding surfaces. LRA Section 2.4 summarizes the screening results for structures. For example, LRA Section 2.4.3 and Table 2.4-3 summarize the screening results for the intake structure. LRA Section 2.4.5 and Table 2.4-5 summarize the screening results for the VHS. The structural components common to all structures such as piping supports were categorized as bulk commodities. LRA Section 2.4.6 and Table 2.4-6 summarize the screening results for structural bulk commodities.2.1.5.3.2  Staff Evaluation The staff reviewed the applicant's methodology for identifying structural components that are subject to an AMR as required in 10 CFR 54.21(a)(1). As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the activity, and evaluated the screening results for several structures that were identified in-scope of license renewal. The applicant's AM reports, as described in the audit report, provided detailed implementationguidance on the applicant's process for identifying and screening structural components that are subject to an AMR. The report stated that all structural components that perform an intended function and are passive and long-lived are subject to an AMR. In addition, the screening results for each system were described in separate AM reports for each system.
2-33The staff reviewed the applicant's methodology used for structural screening described inLRA sections noted above, and in applicants implementing guidance and AM reports The applicant performed the screening review in accordance with the implementation guidance and captured pertinent structure design information, component, materials, environments, and effects of aging. The staff confirmed that the applicant used the lists of passive SCs embodied in the regulatory guidance as an initial starting point and supplemented that list with additional items unique to the site or for which a direct match to the generic lists did not exist (i.e.,
material/environment combinations). As one of the general rules for structural screening, the applicant determined that components which support or interface with electrical components such as, cable trays, conduits, instrument racks, panels and enclosures, were assessed as structural components. The boundary for a structure was the entire building including base slabs, foundations, walls,beams, slabs, and steel superstructure. The AM reports identified each individual SC andindicated if the component is subject to an AMR. Each component was identified as a component, as a component type (door, gate, anchor support, strut, or siding for example), or as a material. The applicant provided the staff with a detailed discussion that described the screening methodology, as well as the screening reports for a selected group of structures. The staff also examined the applicant's results from the implementation of this methodology byreviewing several of the plant structures (intake structure and VHS) identified as being in-scope.
As part of this review, the staff reviewed the AM reports to verify that the applicant had performed a comprehensive evaluation and had identified the relevant structural components as part of their evaluation. The review included the evaluation of in-scope components, the corresponding component-level intended functions, and the resulting list of components subject to an AMR. The staff also discussed the process and results with the applicant. The staff did not identify any discrepancies between the methodology documented and the implementation
 
results.2.1.5.3.3  Conclusion Based on its review of the LRA, the applicant's detailed screening implementation procedures,and a sampling of structural screening results, the staff concludes that the applicant's methodology for identification of passive, long-lived structural component types within the scope of License renewal and subject to an AMR meets 10 CFR 54.21(a)(1) requirements.2.1.5.4  Electrical Component Screening2.1.5.4.1  Summary of Technical Information in the Application In the LRA Section 2.1.2.3, "Screening of Electrical and Instrumentation and Control Systems,"the applicant discussed the use of NEI 95-10, Appendix B, "Typical Structure, Component and Commodity Groupings and Active/ Passive Determinations for the Integrated Plant Assessment," which identifies electrical commodities considered to be passive. The electrical commodity groups were identified and cross-referenced to the appropriate NEI 95-10 commodity.
2-34The applicant determined that the majority of EIC commodity groups are active and do notrequire an AMR. Two passive EIC commodity groups were identified that meet the 10 CFR 54.21(a)(1)(i) criterion (components that perform an intended function without moving parts or without a change in configuration or properties):*high-voltage insulators, and*cables and connections, bus, electrical portions of EIC penetration assembliesAdditionally, the pressure boundary function that may be associated with some EICcomponents identified in NEI 95-10, Appendix B (flow elements, vibration probes) was considered in the mechanical AMRs, as applicable. Electrical components supported bystructural commodities (cable trays, conduit and cable trenches) were included in the structural AMRs.The applicant reviewed the passive electrical components to determine those components thatwere replaced based on a qualified life and therefore not subject to an AMR. The applicant determined that the components included in the Environmental Qualification of Electric Components Program per 10 CFR 50.49 are replaced based on qualified life and, therefore are not subject to an AMR. The applicant determined that the AMRs would be performed for the identified passive, non-Environmental Qualification EIC components.2.1.5.4.2  Staff Evaluation The staff reviewed the applicant's methodology used for electrical screening in LRASections 2.1.2.3 and the applicants implementation procedures and AM reports. The applicant used the screening process described in these documents to identify the electrical commodity groups subject to an AMR. The applicant used the VYNPS component database, the stations single line drawings, and cable procurement specifications as data sources to identify the EIC components including fuses-holders. The applicant determined there were no fuse-holders located outside of active devices and subject to an AMR. The staff determined that the applicant had performed screening by initially identifying passiveSCs and subsequently identifying the long-lived SCs contained within the passive SC population. The applicant identified seven commodities that were determined to meet the passive criteria. The seven commodities were further grouped in accordance with NEI 95-10 as (1) cables and connections, electrical portions of penetration assemblies, switchyard bus, transmission bus, transmission conductors and uninsulated ground conductors, and (2) high-voltage insulators. All were included in the "passive component table." The applicant then evaluated the passive commodities contained in the "passive component table" to identify whether they were subject to period replacement based on a qualified life or specified time period (short-lived), or not subject to period replacement based on a qualified life or specified time period (long-lived). The information used to identify short-lived components, which would not be subject to an AMR, included the environmental qualification master list. The 2-35environmental qualification master list identified the short-lived components included in theEnvironmental Qualification program. The remaining passive, long-lived components were included in the "passive, long-lived component table" and were determined to be subject to an AMR.The staff reviewed the information contained in the scoping file, including the "passivecomponent table," and the "passive, long-lived component table," to verify that the applicant had appropriately identified the identified those passive components which were long-lived and not subject to periodic replacement and therefore subject to an AMR. The staff reviewed the screening of selected components to verify the correct implementation of the LRPGs and AM reports. 2.1.5.4.3  Conclusion The staff reviewed the LRA, procedures, electrical drawings, and a sample of the results of thescreening methodology. The staff determines that the applicant's methodology was consistent with the description provided in LRA and the applicant's implementing procedures. On the basis of a review of information contained in the LRA, the applicant's screening implementation procedures, and a sampling review of electrical screening results, the staff concludes that the applicant's methodology for identification of electrical commodity groups subject to an AMR isconsistent with the requirements of 10 CFR 54.21(a)(1), and is therefore acceptable.
 
2.1.5.5  Conclusion for Screening MethodologyBased on its review of the LRA, the screening implementation procedures, discussions with theapplicant's staff, and a sample review of screening results, the staff determines that the applicant's screening methodology is consistent with the guidance of the SRP-LR and has identified passive, long-lived components within the scope of license renewal and subject to an AMR. The staff concludes that the applicant's methodology is consistent with the requirements of 10 CFR 54.21(a)(1) and, therefore, acceptable.2.1.6  Summary of Evaluation FindingsThe information in LRA Section 2.1, the supporting information in the scoping and screeningimplementation procedures and reports, and the information presented during the scoping and screening methodology audit and the applicant's responses to the staff's RAIs dated August 10, 2006, formed the basis of the staff's determination that the applicant's scoping and screening methodology was consistent with the requirements of the Rule. Based on this determination, the staff concludes that the applicant's methodology for identifying SSCs within the scope of license renewal and SCs requiring an AMR is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1), and, therefore, acceptable.
2-362.2  Plant-Level Scoping Results2.2.1  IntroductionIn LRA Section 2.1, the applicant described the methodology for identifying SSCs within thescope of License renewal. In LRA Section 2.2, the applicant used the scoping methodology to determine which SSCs must be included within the scope of License renewal. The staff reviewed the plant-level scoping results to determine whether the applicant has properly identified all systems and structures relied upon to mitigate DBEs, as required by 10 CFR 54.4(a)(1), systems and structures the failure of which could prevent satisfactory accomplishment of any safety-related functions, as required by 10 CFR 54.4(a)(2), and systems and structures relied on in safety analyses or plant evaluations to perform functions required by regulations referenced in 10 CFR 54.4(a)(3).2.2.2  Summary of Technical Information in the ApplicationIn LRA Tables  2.2-1a, 2.2-1b, and 2.2.3, the applicant listed plant mechanical systems,structures, and EIC systems, respectively, within the scope of license renewal. In LRA Tables  2.2-2 and 2.2-4, the applicant listed mechanical systems and structures that are not within the scope of license renewal. Based on the DBEs considered in the plant's CLB, other CLB information relating to nonsafety-related systems and structures, and certain regulated events, the applicant identified plant-level systems and structures within the scope of license renewal as specified by 10 CFR 54.4.2.2.3  Staff EvaluationIn LRA Section 2.1, the applicant described its methodology for identifying systems andstructures within the scope of license renewal and subject to an AMR. The staff reviewed the scoping and screening methodology and provides its evaluation in SER Section 2.1. To verifythat the applicant properly implemented its methodology, the staff's review focused on the implementation results shown in LRA Tables  2.2-1a, 2.2-1b, 2.2-2, 2.2-3, and 2.2-4, to confirm that there were no omissions of plant-level systems and structures within the scope of license renewal.The staff determined whether the applicant properly identified the systems and structures withinthe scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed selected systems and structures that the applicant had not identified as falling within the scope of license renewal to verify whether the systems and structures have any intended functions requiring their inclusion within the scope of license renewal. The staff's review of the applicant's implementation was conducted in accordance with the guidance in SRP-LR Section 2.2, "Plant-Level Scoping Results."In LRA Section 2.2, the staff identified areas in which additional information was necessary tocomplete the review of the applicant's plant-level scoping results. The applicant responded to the staff's RAIs as discussed below.
2-37LRA Table 2.2-4, "Structures Not within the Scope of License Renewal," identifies the officebuilding (administration and service buildings) as not within the scope of license renewal. The table identifies two UFSAR sections as references for office building. UFSAR Section 12.2.1.1.3 is an appropriate reference that identifies the administration building as a seismic Class II structure. However, the second UFSAR Section 12.2.3 is actually for the turbine building and not the administration or service building. In RAI 2.2-1 dated August 16, 2006, the staff requested that the applicant clarify and correct the reference to UFSAR Section 12.2.3 in LRA Table 2.2-4.In its response dated September  20, 2006, the applicant stated that the office building is calledby various names in VYNPS documents: the office building or area, the service building or area, and the administration building. It is sometimes considered part of the turbine building and in other contexts described as a separate building. In UFSAR Section 12.2.3, this area is listed as the "service area" that is part of the turbine building. Although the reference to UFSAR Section 12.2.3 is correct, this reference could have been omitted since UFSAR Section 12.2.3 only lists the service area and provides no description or further information about the service area. The applicant stated that the office building is not within the scope of license renewal. Based on its review, the staff finds the applicant's response to RAI 2.2-1 acceptable becausethe applicant clarified the use of the term office building; therefore, the staff's concern described in RAI 2.2-1 is resolved.The pressure regulator and TG control system is described in USFAR Section 7.11. Thepurpose of the TG control system is to control steam flow and pressure to the turbine and to protect the turbine from overpressure or excessive speed. The TG controls work in conjunction with the "nuclear steam system" controls to maintain essentially constant reactor pressure and limit reactor transients during load variations. The LRA does not address the nuclear steam system, nor does it appear to refer to UFSAR Section 7.11 in the text. In RAI 2.2-3 dated August 16, 2006, the staff requested that the applicant clarify whether the nuclear steam system controls are included within the scope of license renewal, or explain the basis for their exclusion. In its response dated September  20, 2006, the applicant stated that the pressure regulator andTG control system as described in UFSAR Section 7.11 is an electrical and instrumentation and control (EIC) portion of the main TG system listed in LRA Table 2.2-2. The TG system provides automatic and manual controls to maintain essentially constant reactor pressure and limit reactor transients during load variations. Components in the system control steam flow and pressure to protect the turbine from overpressure or excessive speed. As discussed in the introduction to Table 2.2-1b, "EIC Systems within the Scope of License Renewal (Bounding Approach)," all EIC commodities contained in electrical and mechanical systems are in-scope by default. LRA Table 2.2-1b provides the list of electrical systems that do not include mechanical components that meet the scoping criteria of 10 CFR 54.4. Systems (such as the TG system) with mechanical components that meet the scoping criteria of 10 CFR 54.4 are listed in LRA Table 2.2-la. The pressure regulator and TG control system as described in UFSAR Section 7.1 1 are not considered separate systems and therefore are not listed in LRA Table 2.2-la. However, the components that perform this function are in-scope as EIC components. The applicant stated that the nuclear steam system controls are within the scope of license renewal.
2-38Based on its review, the staff finds the applicant's response to RAI 2.2-3 acceptable becausethe applicant stated all EIC commodities contained in electrical and mechanical systems are in-scope by default; therefore, the staff's concern described in RAI 2.2-3 is resolved.In response to concerns raised during the license renewal inspection, documented in theVermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report 05000271/2007006, dated June 4, 2007, the applicant placed fluid system components within the turbine building within the scope of license renewal. The applicants original scoping had determined that most of the turbine building was not within the scope of license renewal with a few exceptions, i.e., the diesel generator rooms, a few limited areas, and segments of the service water and diesel fuel oil systems. The inspection team determined that the scoping of segments of the service water and diesel fuel oil systems were not, in some instances, in accordance with guidance and that safety-related cables for reactor protection system functions had not been appropriately considered. The applicant added the turbine building to the scope of license renewal. The applicant's response to the inspection report and subsequent submittal of supplementaryinformation related to implementation of an enhanced scoping review are documented in the their letters to the NRC dated July 3, 2007, July 30, 2007, and August 16, 2007. As a result of implementing of scoping review changes, the applicant expanded the scope of license renewal and added the following mechanical systems and associated in-scope components:
* HD and HV instruments system
* air evacuation system
* building (drainage system components)system
* circulating water priming system
* extraction steam system
* heater drain system
* heater vent system
* hydrogen water chemistry system
* make-up demineralizer system
* seal oil system
* turbine building closed cooling water system
* main turbine generator
* turbine lube oil systemThe above 13 mechanical systems were added to LRA Table 2.2-1a and removed from LRATable 2.2-2.The following mechanical systems had system boundary changes. For these systems, newcomponent types were added that affected the scoping and screening results in the LRA. For systems listed below, new components, materials or environments that affected the AMR results in the LRA were added.
* augmented offgas system
* condensate system
* condensate demineralizer system
* condensate storage and transfer system 2-39
* circulating water system
* feedwater system
* fuel oil system
* fire protection system
* house heating boiler system
* heating, ventilation, and air conditioning system
* potable water system
* stator cooling system
* sampling system
* service water systemThe effects of the above changes are evaluated in the applicable sections of this SER.
The staff reviewed the selected systems and structures that the applicant had not identified asfalling within the scope of license renewal to verify whether the systems and structures have any intended functions that would require their inclusion within the scope of license renewal in accordance with 10 CFR 54.4. The staff's review of the applicant's implementation was conducted in accordance with the guidance described in SRP-LR Section 2.2, "Plant-Level Scoping Results."2.2.4  ConclusionThe staff reviewed LRA Section 2.2, the RAI responses, the response to the license renewalinspection concerns, and the UFSAR supporting information to determine whether the applicant failed to identify any systems and structures within the scope of license renewal. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified in accordance with 10 CFR 54.4 the systems and structures within the scope of license renewal.2.3  Scoping and Screening Results: Mechanical SystemsThis section documents the staff's review of the applicant's scoping and screening results for mechanical systems. Specifically, this section discusses:
* reactor coolant system
* engineered safety features
* auxiliary systems
* steam and power conversion systemsIn accordance with the requirements of 10 CFR 54.21(a)(1), the applicant's IPA must listpassive, long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff's review focused on the implementation results. This focus allowed the staff to confirm that there were no omissions of mechanical system components that meet the scoping criteria and are subject to an AMR.The staff's evaluation of the information in the LRA was the same for all mechanical systems.The objective was to determine whether the applicant has identified, in accordance with 10 CFR 54.4, components and supporting structures for specific mechanical systems that 2-40appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant'sscreening results to verify that all passive, long-lived components were subject to an AMR in accordance with 10 CFR 54.21(a)(1).In its scoping evaluation, the staff reviewed the applicable LRA sections and componentdrawings, focusing on components that have not been identified as within the scope of license renewal. The staff reviewed relevant licensing basis documents, including the UFSAR, for each mechanical system to determine whether the applicant has omitted from the scope of license renewal components with intended functions as required by 10 CFR 54.4(a). The staff also reviewed the licensing basis documents to determine whether the LRA specified all intended functions as required by 10 CFR 54.4(a). The staff requested additional information to resolve any omissions or discrepancies identified.After its review of the scoping results, the staff evaluated the applicant's screening results. Forthose SCs with intended functions, the staff sought to determine whether: (1) the functions are performed with moving parts or a change in configuration or properties or (2) the SCs are subject to replacement after a qualified life or specified time period, as required by 10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). The staff requested additional information to resolve any omissions or discrepancies identified.Two-Tier Scoping Review Process for Balance of Plant (BOP) SystemsOf the 78 mechanical systems in the LRA, 44 are BOP systems which include most of theauxiliary systems and all of the steam and power conversion systems. The staff performed a two-tier scoping review for these BOP systems. The two-tier scoping review process consists of Tier-1 and Tier-2 scoping reviews. The staffreviewed the LRA and UFSAR descriptions focusing on the system intended function to screen all the BOP systems into two groups based on the following screening criteria:
* safety importance/risk significance
* potential for system failure to cause failure of redundant safety system trains
* operating experience indicating likely passive failures
* systems subject to omissions based on previous LRA reviewsExamples of the safety important/risk significant systems are the instrument air (IA) system, thediesel generator (DG) and support systems, and the SW system, based on the results of the individual plant examination for VYNPS. An example of a system whose failure could result incommon cause failure of redundant trains is a drain system providing flood protection.
Examples of systems with operating experience indicating likely passive failures include MS system, feedwater system, and SW system. Examples of systems with identified omissions in previous LRA reviews include spent fuel cooling system and makeup water sources to safety systems.From the 44 BOP systems, the staff selected 23 systems for a detailed "Tier-2" scoping reviewas described above. For the remaining 21 BOP systems, the staff performed a "Tier-1" scoping review of the LRA (which may have not included detailed boundary drawings) and UFSAR that 2-41would identify apparent missing components for an AMR. The following is a list of these 21systems:
* service air (SA)
* SA and IA instruments
* condensate demineralizer
* RWCU filter demineralizer
* motor generator lube oil (MGLO)
* potable water
* equipment RIP
* stator cooling
* main steam, extraction steam and auxiliary steam instruments
* heater drain and heater vent (HD and HV) instruments
* air evacuation
* building (drainage system components)
* circulating water priming
* extraction steam
* heater drain
* heater vent
* make-up demineralizer
* seal oil
* turbine building closed cooling water
* main turbine generator
* turbine lube oilThe staff examined the applicant's environmental report in LRA Appendix E, Attachment E.1,"Evaluation of Probabilistic Safety Analysis Model," to verify that there is no risk significant system on the above list. None of the 21 systems is a significant contributor to the risk reduction worth rankings to core damage frequency or involved in the significant initiating events. Systems Identified for InspectionThe staff used an inspection to verify 10 CFR 54.4(a)(2) scoping results. The staff identifiedseveral systems for the regional inspection team to include in its scoping and screening inspection. These systems had been included as within the scope of license renewal by the applicant as a result of the 10 CFR 54.4(a)(2) review. The staff requested that the inspection include a sampling review of the engineering report (if available), plant layout drawings and other documentation, and walkdowns of the plant areas that contain these systems and associated components. The systems identified for inspection include:
* augmented off-gas system
* circulating water system
* reactor water clean-up systemAs a result of the regional inspection and other staff inquiry, the applicant issued letters to theNRC dated July 3, 2007, July 30, 2007, and August 16, 2007. These letters provided supplementary information that addressed resolution of the issues identified during the 2-42inspection. Refer to SER Sections 2.3.3.13A, 2.3.3.13E, and 2.3.3.13M for additional discussion.2.3.1  Reactor Coolant SystemLRA Section 2.3.1 states that the purposes of the reactor coolant system (RCS) are to housethe reactor core and to contain and transport the fluids coming from or going to the reactor core. The RCS includes the reactor vessel and internals, the reactor recirculation system, CRD system, and Class 1 components that comprise the reactor coolant pressure boundary (RCPB),
including MS and feedwater components. The applicant described the RCS as including the nuclear boiler (NB) system, the CRD system, and the hydraulic control unit (HCU) system associated with the CRDs.The applicant described the supporting SCs of the RCS in the following LRA sections:
* 2.3.1.1reactor vessel
* 2.3.1.2reactor vessel internals
* 2.3.1.3reactor coolant pressure boundaryThe staff's findings on review of LRA Sections 2.3.1.1 - 2.3.1.3 are in SERSections 2.3.1.1 - 2.3.1.3, respectively. The staff's review of the NB, CRD, and HCU systems proceeded as follows:Summary of Technical Information in the Application. LRA Section 2.3.1 describes the RCS,including the NB, CRD, and HCU systems. Summaries of each system follow:
NB System. The NB system consists of Class 1 components, non-Class 1 components, and thefollowing subsystems: reactor vessel and internals, reactor recirculation, MS, feedwater (Class 1), and nuclear boiler vessel instrumentation system (NBVIS). The reactor vessel is a welded vertical cylindrical pressure vessel with hemispherical heads. The cylindrical shell and hemispherical heads are fabricated of low-alloy steel plate. The vessel bottom head is welded directly to the vessel shell. The flanged upper head is secured to the vessel shell by studs and nuts. The reactor vessel includes nozzles, safe ends, CRD penetrations, instrument penetrations, and a support skirt. Additional details of the reactor vessel are described in LRA Section 2.3.1.1. The reactor vessel internals distribute the flow of coolant, locate and support the fuel assemblies, and provide an inner volume containing the core that can be flooded following a break in the nuclear system process barrier external to the reactor pressure vessel.
Additional details of the reactor vessel internals are described in LRA Section 2.3.1.2.Reactor recirculation provides a variable moderator (coolant) flow to the reactor core foradjusting reactor power level. Adjustment of the core coolant flow rate changes reactor power output, thus following plant load demand without adjusting control rods. The recirculation system is designed with sufficient fluid and pump inertia that fuel thermal limits cannot be exceeded as a result of recirculation system malfunctions. The reactor core is cooled by demineralized water which enters the lower portion of the core and boils as it flows upward around the fuel rods. The steam leaving the core is dried by steam separators and dryers in the upper portion of the reactor vessel, then directed to the turbine through four MS lines. The steam supply for high-pressure coolant injection (HPCI) and reactor core isolation cooling 2-43(RCIC) turbine operation is provided by connections to the MS piping. Class 1 feedwater linesprovide water to the reactor vessel, entering near the top of the vessel downcomer annulus.
Two feedwater lines divide and enter the vessel through four nozzles. Feedwater lines are also for injection of HPCI and RCIC. The NBVIS monitors reactor vessel parameters. The NBVIS is designed (1) to initiate and provide trip signals to interfacing plant safety systems, (2) to provide signals to interfacing plant nonsafety systems, and (3) to provide plant process parameter information necessary for normal, transient, and abnormal (including post-accident) operations.
The NBVIS instrument sensing lines, including restriction orifices and excess flow check valves, are parts of the RCPB.The NB system has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related SSCs in the NB system could prevent the satisfactory accomplishment of a safety-related function. In addition, the NB system performs functions that support fire protection safe shutdown capability analysis and SBO coping analysis.LRA Table 2.3.3-13-25 identifies the following nonsafety-related components types of the NBsystem within the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* flow element
* orifice
* piping
* tubing
* valve bodyThe nonsafety-related NB system component intended function within the scope of licenserenewal is to provide a pressure boundary.CRD System. The CRDs provide a means to control changes in core reactivity by incrementallypositioning neutron-absorbing control rods within the reactor core in response to manual control signals. The CRD subsystem must shut down the reactor quickly (scram) by inserting control rods rapidly into the core in response to a manual or automatic signal.
The CRD system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the CRD system could prevent the satisfactory accomplishment of a safety-related function. In addition, the CRD system performs functions that support fire protection and ATWS.LRA Table 2.3.3-13-5 identifies the following nonsafety-related CRD system component typeswithin the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* orifice
* piping
* pump casing 2-44
* strainer housing
* tank
* tubing
* valve bodyThe nonsafety-related CRD component intended function within the scope of license renewal isto provide a pressure boundary.HCU System. The HCU system controls the water flow to the CRDs both for normal operationand during a reactor scram. Each HCU furnishes pressurized water upon signal to a CRD. The drive then positions its control rod as required. Water discharged from the drives during a scram flows through the HCUs to the scram discharge volume. Water discharged from a drive during a normal control rod positioning operation flows through its HCU and the exhaust header to the RWCU system discharge line. The HCU system has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related SSCs in the HCU system could prevent the satisfactory accomplishment of a safety-related function. In addition, the HCU system performs functions that support fire protection safe shutdown capability analysis and SBO coping analysis.LRA Table 2.3.3-13-19 identifies the following nonsafety-related HCU system component typeswithin the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* piping
* tubing
* valve bodyThe nonsafety-related HCU system component intended function within the scope of licenserenewal is to provide a pressure boundary.Staff Evaluation. The staff reviewed LRA Section 2.3.1, UFSAR Sections 3.4, 3.5, 4.1 through4.6, and 7.18 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3, "Scoping and Screening Results: Mechanical Systems."The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant had not omitted any components with intended functions from the scope of license renewal required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant had identified as within the scope of license renewal to verify that no passive and long-lived components subject to an AMR had been omitted as required by 10 CFR 54.21(a)(1).
Conclusion. The staff reviewed the LRA to determine whether the applicant failed to identify anySSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the NB, CRD, and HCU systems components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as 2-45required by 10 CFR 54.21(a)(1).2.3.1.1  Reactor Vessel2.3.1.1.1  Summary of Technical Information in the Application LRA Section 2.3.1.1 describes the reactor vessel, which contains the nuclear fuel core, coresupport structures, control rods, and other parts directly associated with the core. The major components of the reactor vessel are the reactor pressure vessel shell, bottom head, upper closure head, flanges, studs, nuts, nozzles and safe ends. The component evaluation boundaries are the welds between the safe ends and attached piping and the interface flanges for bolted connections. Thermal sleeves welded to vessel nozzles or safe ends, CRD stub tubes, CRD housings, in-core housings, the vessel support skirt, and vessel interior and exterior welded attachments also were included.LRA Table 2.3.1-1 identifies the following reactor vessel component types within the scope oflicense renewal and subject to an AMR:
* bolting
* heads and shell
* nozzles and penetrations
* safe ends, thermal sleeves, flanges, and caps
* vessel attachments and supportsThe reactor vessel component intended functions within the scope of license renewal includethe following:
* pressure boundary
* structural or functional support for safety-related equipment2.3.1.1.2  Staff Evaluation The staff reviewed LRA Section 2.3.1.1 and the UFSAR using the evaluation methodologydescribed in SER Section 2.3 and the guidance in SRP-LR Section 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).In LRA Table 2.3.1-1, the reactor vessel leakage monitoring piping was not identified as acomponent within the scope of license renewal and requiring an AMR. In RAI 2.3.1.1-1 dated July 13, 2006, the staff requested that the applicant clarify whether the subject components were included within the scope of license renewal. In its response dated August 15, 2006, the applicant stated that the subject components were 2-46included within the scope of license renewal in accordance with the category 'piping and fittingsless than 4 inches NPS,' 'orifices (instrumentation),' and 'valve bodies less than 4 inches NPS' as part of RCPB components in Table 2.3.1-3. Based on its review, the staff finds the applicant's response to RAI 2.3.1.1-1 acceptable because the reactor vessel leakage monitoring piping was proven to be in-scope. The staff's concern described in RAI 2.3.1.1-1 is resolved.In RAI 2.3.1.1-2 dated July 13, 2006, the staff requested that the applicant clarify if the scramdischarge piping and volume are within the scope of license renewal because the subject components were not discussed in LRA Section 2.3.1.1.In its response dated August 15, 2006, the applicant stated that the subject components wereincluded within the scope of license renewal and subject to an AMR in accordance with the category 'piping and fittings less than 4 inches NPS,' 'orifices (instrumentation),' and 'valve bodies less than 4 inches NPS' as part of RCPB components in Table 2.3.1-3. Based on its review, the staff finds the applicant's response to RAI 2.3.1.1-2 acceptable because the scram discharge piping and volume were proven to be in-scope. The staff's concern described in RAI 2.3.1.1-2 is resolved.In RAI 2.3.1.1-3 dated July 13, 2006, the staff requested that the applicant include the CRDhousing supports within the scope of license renewal and requiring an AMR because the subject components were not discussed in LRA Section 2.3.1.1, "Reactor Vessel."In its response dated August 15, 2006, the applicant stated that the subject components wereconsidered in the category of structural elements and included in the line item for components and piping supports ASME Class 1, 2, 3 in Table 2.4-6, "Bulk Commodities Components Subject to an AMR." Based on its review, the staff finds the applicant's response to RAI 2.3.1.1-3 acceptable because the CRD housing supports were proven to be in-scope. The staff's concern described in RAI 2.3.1.1-3 is resolved.2.3.1.1.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the reactor vessel components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.1.2  Reactor Vessel Internals2.3.1.2.1  Summary of Technical Information in the Application LRA Section 2.3.1.2 describes the reactor vessel internals, which are designed to distribute thereactor coolant flow delivered to the vessel, to locate and support the fuel assemblies, and to contain the core in an inner volume that can be flooded following a break in the nuclear system process barrier. The reactor vessel internals are the control rod guide tubes, core plate, CS lines in the vessel, differential pressure and SLC line, feedwater spargers, fuel support pieces, in-core guide tubes, in-core dry tubes, local power range monitors, jet pump assemblies and jet 2-47pump instrumentation, shroud (including shroud stabilizers), shroud head and steam separatorassembly, shroud support, steam dryer, surveillance sample holders, top guide, and vessel head spray line.LRA Table 2.3.1-2 identifies the following reactor vessel internals component types within thescope of license renewal and subject to an AMR:
* control rod guide tubes
* core plate assembly
* core spray lines
* fuel support pieces
* in-core dry tubes
* in-core guide tubes
* jet pump assemblies
* jet pump casting
* shroud
* shroud repair hardware
* shroud support
* steam dryer
* top guideThe reactor vessel internals component intended functions within the scope of license renewalinclude the following:
* flow distribution
* boundary of a volume in which the core can be flooded and adequately cooled in theevent of a breach in the nuclear system process barrier external to the reactor vessel
* pressure boundary
* structural or functional support for safety-related equipment
* structural integrity so loose parts are not introduced2.3.1.2.2  Staff EvaluationThe staff reviewed LRA Section 2.3.1.2 and the UFSAR using the evaluation methodologydescribed in SER Section 2.3 and the guidance in SRP-LR Section 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.1.2.3  Conclusion 2-48The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the reactor vessel internals components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.1.3  Reactor Coolant Pressure Boundary2.3.1.3.1  Summary of Technical Information in the Application LRA Section 2.3.1.3 describes the RCPB, which maintains a high-integrity pressure boundaryand fission product barrier inside the primary containment and to the first isolation outside the primary containment. Class 1 piping attached to the vessel nozzles or safe ends, including the welded joints, Class 1 pumps, and Class 1 boundary isolation valves, are included in this review. Connected Class 2 piping not part of another AMR, including vents, drains, leakoff, sample lines, and instrumentation lines up to the transmitters, is included as far as necessary to complete the RCS pressure boundary.LRA Table 2.3.1-3 identifies the following RCPB component types within the scope of licenserenewal and subject to an AMR:
* bolting (flanges, valves, etc.)
* condensing chambers
* detector (CRD)
* drive (CRD)
* driver mount (RR)
* filter housing (CRD)
* flow elements (RR), (SLC)
* orifices (instrumentation)
* piping and fittings < 4 inches NPS
* piping and fittings > 4 inches NPS
* pump casing and cover (RR)
* pump cover thermal barrier (RR)
* restrictors (MS)
* rupture disc (CRD)
* tank (CRD accumulator)
* thermowell
* valve bodies < 4 inches NPS
* valve bodies > 4 inches NPSThe RCPB component intended functions within the scope of license renewal include thefollowing:
* flow control
* pressure boundary 2-492.3.1.3.2  Staff EvaluationThe staff reviewed LRA Section 2.3.1.3 and the UFSAR using the evaluation methodologydescribed in SER Section 2.3 and the guidance in SRP-LR Section 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.1.3.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the RCPB components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2  Engineered Safety FeaturesIn LRA Section 2.3.2, the applicant identified the SCs of the engineered safety features that aresubject to an AMR for license renewal.The applicant described the supporting SCs of the engineered safety features in the followingLRA sections:
* 2.3.2.1residual heat removal
* 2.3.2.2core spray
* 2.3.2.3automatic depressurization
* 2.3.2.4high pressure coolant injection
* 2.3.2.5reactor core isolation cooling
* 2.3.2.6standby gas treatment
* 2.3.2.7primary containment penetrationsThe staff's review findings regarding LRA Sections 2.3.2.1 - 2.3.2.7 are presented in SERSections 2.3.2.1 - 2.3.2.7, respectively.
2-502.3.2.1  Residual Heat Removal2.3.2.1.1  Summary of Technical Information in the Application LRA Section 2.3.2.1 describes the RHR system, which removes decay heat energy from thereactor during both operational and accident conditions. The RHR system consists of two closed loops, each with two pumps in parallel, one heat exchanger, and the necessary valves and instrumentation. The RHR heat exchanger in each loop is cooled by the residual heat removal service water (RHRSW) system. The RHR system has eight modes of operation:
(1) the low-pressure coolant injection (LPCI) mode takes suction from the suppression pool and injects flow into the core region of the reactor vessel through one of the two reactor recirculation loops to restore and maintain the water level of the reactor vessel following a loss of coolant accident (LOCA), (2) the containment spray cooling mode takes suction from the suppression pool and injects flow into spray headers located in the drywell and suppression chamber to reduce containment pressure and temperature following a LOCA by cooling any non-condensables and condensing any steam present, (3) the suppression pool cooling mode takes water from the suppression pool, passes it through the RHR heat exchangers, and returns flow to the suppression pool to remove heat added to the suppression pool, (4) the shutdown cooling mode takes water from the reactor vessel via the reactor recirculation A loop suction piping, passes it through the RHR heat exchangers, and returns flow to the reactor through the recirculation lines to remove sensible and decay heat from the reactor during shutdown, (5) the alternate shutdown cooling mode provides a cooling path if the normal shutdown cooling path is inoperable and can be initiated from the control room. RHR pumps take water from the suppression pool, pass it through RHR heat exchangers and inject into the vessel via RHR injection valves. Relief valves on the steam lines are open to allow overflow to the suppression pool, (6) the augmented fuel pool cooling (FPC) mode takes water from the FPC system, passes it through RHR heat exchangers, and returns flow to the FPC system to assist in FPC during reactor shutdown periods and the alternate cooling mode of operation and is not a safety function of RHR, (7) the emergency reactor vessel fill mode, which is beyond the design basis mode of operation, provides a cross-tie between the RHRSW system and RHR piping loop A. The RHRSW pumps take suction from the SW system and inject flow into the reactor vessel through RHR piping to provide a source of water to keep the reactor core covered (and fill containment) in the event that core standby cooling system (CSCS) pumps are lost due to loss of containment pressure or adequate core cooling cannot be assured, and (8) the alternate shutdown mode uses the RHR alternate shutdown panel to control the minimum valving required for vessel injection, torus cooling, and shutdown cooling modes to achieve and maintain cold shutdown conditions during a postulated control room or cable vault fire which eliminates normal means of system control.The RHR system has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related SSCs in the RHR system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the RHR system performs functions that support fire protection safe shut down capability analysis.LRA Tables  2.3.2-1 and 2.3.3-13-33 identify the following RHR system component types withinthe scope of license renewal and subject to an AMR:
2-51
* bolting
* cyclone separator
* heat exchanger (bonnet)
* heat exchanger (shell)
* heat exchanger (tubes)
* nozzle
* orifice
* piping
* pump casing
* strainer
* tank
* thermowell
* tubing
* valve bodyThe RHR system component intended functions within the scope of license renewal include thefollowing:
* flow control
* filtration
* heat transfer
* pressure boundary2.3.2.1.2  Staff Evaluation The staff reviewed LRA Sections 2.3.2.1 and 2.3.3.13, and UFSAR Sections 4.8 and 6.4.4using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LRSection 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).The LPCI coupling was identified in the Boiling Water Reactor Vessel and Internals Project(BWRVIP) -06 Report as a safety-related component. In RAI 2.3.2.1-1 dated July 13, 2006, the staff requested that the applicant identify LPCI couplings in the LRA as within the scope of license renewal and subject to an AMR if they are part of VYNPS.In its response dated August 15, 2006, the applicant responded that VYNPS does not haveLPCI couplings. Based on its review, the staff finds the applicant's response to RAI 2.3.2.1-1 acceptable because there are no LPCI couplings in-scope or subject to an AMR since there are no LPCI couplings at VYNPS. The staff's concern described in RAI 2.3.2.1-1 is resolved.In RAI 2.3.2.1-2 dated July 13, 2006, the staff requested the applicant clarify whether vortexbreakers are employed in the emergency core cooling system (ECCS) pump suction lines at 2-52VYNPS, and if so, identify and include these passive components in-scope requiring an AMR. In its response dated August 15, 2006, the applicant said that during the IPA for VYNPS, a review of site documentation for all in-scope mechanical systems, including licensing basis and DBDs, as well as the site component database and drawings was completed. The applicant determined that no vortex breakers were required to support system intended functions in the scope of license renewal per 54.4 (a)(1-3), and therefore, vortex breakers are not included in the LRA for VYNPS. Based on its review, the staff finds the applicant's response to RAI 2.3.2.1-2 acceptable because no vortex breakers support the intended function of the ECCS pump suction lines at VYNPS. The staff's concern described in RAI 2.3.2.1-2 is resolved.2.3.2.1.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the RHR system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2.2  Core Spray2.3.2.2.1  Summary of Technical Information in the Application LRA Section 2.3.2.2 describes the CS system, which in conjunction with other CSCS, providesadequate core cooling for all design basis break sizes up to and including double-ended breaks of the reactor recirculation system piping. The CS system protects the core in large breaks in the nuclear system when the RCIC and HPCI systems are unable to maintain reactor vessel water level. CS system protection also extends to small breaks in which the RCIC and HPCI systems are unable to maintain reactor vessel water level and automatic depressurization lowers reactor vessel pressure so the LPCI and the CS systems can cool the core. The CS system has two independent loops, each with a centrifugal water pump driven by an electric motor, a spray sparger in the reactor vessel above the core, and piping and valves to convey water from the suppression pool (primary safety-related source) or condensate storage tank (backup source) to the sparger.The CS system has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related SSCs in the CS system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the CS system performs functions that support fire protection safe shutdown capability analysis and SBO coping analysis.LRA Tables  2.3.2-2 and 2.3.3-13-6 identify the following CS system component types withinthe scope of license renewal and subject to an AMR:
* bolting
* bearing housing
* cyclone separator
* flow nozzle
* orifice 2-53
* piping
* pump casing
* strainer
* tubing
* valve bodyThe CS system component intended functions within the scope of license renewal include thefollowing:
* flow control
* filtration
* pressure boundary 2.3.2.2.2  Staff EvaluationThe staff reviewed LRA Section 2.3.2.2 and UFSAR Sections 6.3 and 6.4.3 using the evaluationmethodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.2.2.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the CS system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2.3  Automatic Depressurization2.3.2.3.1  Summary of Technical Information in the Application LRA Section 2.3.2.3 describes the automatic depressurization system (ADS), which actuatesnuclear system pressure relief valves to depressurize the nuclear system automatically in a LOCA in which the HPCI system fails to deliver rated flow or break flow exceeds HPCI capacity (intermediate break). The depressurization of the nuclear system allows low-pressure standby cooling systems to supply enough cooling water to cool the fuel adequately. The ADS functions as one of the CSCSs. The ADS, in combination with the LPCI and CS systems, serves as a backup to the HPCI system.The ADS has safety-related components relied upon to remain functional during and followingDBEs. The failure of nonsafety-related ADS SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the ADS performs functions that support fire protection safe shutdown capability analysis and SBO coping analysis.
2-54LRA Table 2.3.2-3 identifies the following ADS component types within the scope of licenserenewal and subject to an AMR:
* bolting
* orifice
* piping
* tubing
* valve bodyThe ADS component intended functions within the scope of license renewal include thefollowing:
* flow control
* pressure boundary2.3.2.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.3 and UFSAR Sections 4.4 and 6.4.2 using the evaluationmethodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.2.3.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the ADS components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2.4  High Pressure Coolant Injection2.3.2.4.1  Summary of Technical Information in the Application LRA Section 2.3.2.4 describes the HPCI system, which cools the reactor core adequately in asmall break in the nuclear system with subsequent coolant loss which does not cause rapid depressurization of the reactor vessel. It performs this function simultaneously with a loss of normal auxiliary power. The HPCI system permits shutdown of the reactor by maintaining sufficient reactor vessel water inventory until the reactor vessel is depressurized. HPCI continues until reactor vessel pressure is below that at which the LPCI or CS system can maintain core cooling.
2-55The HPCI system has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related SSCs in the HPCI system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the HPCI system performs functions that support fire protection and SBO coping analysis.LRA Tables  2.3.2-4 and 2.3.3-13-20 identify the following HPCI system component types withinthe scope of license renewal and subject to an AMR:
* bearing housing
* bolting
* drain pot
* fan housing
* filter housing
* gear box
* governor housing
* heat exchanger (bonnet)
* heat exchanger (shell)
* heat exchanger (tubes)
* orifice
* piping
* pump casing
* sight glass
* steam trap
* strainer
* strainer housing
* tank
* thermowell
* tubing
* turbine casing
* valve bodyThe HPCI system component intended functions within the scope of license renewal include thefollowing:
* flow control
* filtration
* heat transfer
* pressure boundary2.3.2.4.2  Staff Evaluation The staff reviewed LRA Sections 2.3.2.4 and 2.3.3.13, and UFSAR Sections 6.3 and 6.4 usingthe evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the 2-56applicant has identified as within the scope of license renewal to verify that the applicant hasnot omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.2.4.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the HPCI system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2.5  Reactor Core Isolation Cooling2.3.2.5.1  Summary of Technical Information in the Application LRA Section 2.3.2.5 describes the RCIC and the condensate storage and transfer (CST)systems. In the event of feedwater isolation with a simultaneous loss of normal auxiliary power, the RCIC system replaces the normal sources of makeup water to the reactor vessel to prevent uncovering of the core when it operates automatically without the use of any CSCSs. The RCIC system consists of a steam turbine-driven pump designed to supply water from either the condensate storage tank or the suppression pool to the reactor via the feedwater spargers. The purpose of the CST system is to provide a source of water to various plant systems, including the HPCI and RCIC systems (preferred source), CS system (as a backup source or for testing),
the CRD system (backup source), and the spent fuel pool (fill and makeup source). The CST system connects to the condensate system to make up or draw off condensate to or from the hotwell. The CST system consists of the condensate storage tank, two condensate transfer pumps, piping, and valves.The RCIC and CST systems have safety-related components relied upon to remain functionalduring and following DBEs. The failure of nonsafety-related SSCs in the system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the systems perform functions that support fire protection safe shutdown capability analysis and SBO coping analysis.LRA Tables  2.3.2-5, 2.3.3-13-7, and 2.3.3-13-31 identify the following RCIC and CST systemscomponent types within the scope of license renewal and subject to an AMR:
* bolting
* condenser
* drain pot
* filter housing
* flow indicator
* heat exchanger (bonnet)
* heat exchanger (shell)
* heat exchanger (tubes)
* orifice
* piping 2-57
* pump casing
* rupture disk
* sight glass
* steam heater
* steam trap
* strainer
* strainer housing
* tank
* thermowell
* tubing
* turbine casing
* valve bodyThe component intended functions within the scope of license renewal include the following:
* flow control
* filtration
* heat transfer
* pressure boundary2.3.2.5.2  Staff Evaluation The staff reviewed LRA Sections 2.3.2.5 and 2.3.3.13, and UFSAR Sections 4.7 and 11.8.3.8using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LRSection 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.2.5.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the RCIC and CST systems components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2.6  Standby Gas Treatment2.3.2.6.1  Summary of Technical Information in the Application LRA Section 2.3.2.6 describes the standby gas treatment (SBGT) system, which processesgaseous effluent from the primary and secondary containments when required to limit the 2-58discharge of radioactive materials to the environs and to limit ex-filtration from the secondarycontainment during primary containment isolation. This processing is accomplished by two trains, each capable of maintaining a negative pressure in the secondary containment and processing one net secondary containment volume of air per day through high-efficiency filters.
The system functions as part of the secondary containment system. The SBGT system consists of two complete, independent trains, each a backup for the other and sized to handle the full system requirement. Each train has a demister, electric heaters, two high-efficiency particulate filters, a carbon absorber, a fan, and miscellaneous valves.The SBGT system has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related SSCs in the SBGT system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Tables  2.3.2-6 and 2.3.3-13-38 identify the following SBGT system component typeswithin the scope of license renewal and subject to an AMR:
* bolting
* duct
* fan housing
* filter
* filter housing
* filter unit housing
* orifice
* piping
* sight glass
* thermowell
* tubing
* valve bodyThe SBGT system component intended functions within the scope of license renewal includethe following:
* filtration
* pressure boundary2.3.2.6.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.6 and UFSAR Sections 1.6.2.15 and 5.3.4 using theevaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).
2-592.3.2.6.3  ConclusionThe staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the SBGT system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2.7  Primary Containment Penetrations2.3.2.7.1  Summary of Technical Information in the Application LRA Section 2.3.2.7 describes the primary containment penetrations, which can rapidly isolateall pipes or ducts penetrating the primary containment with a containment barrier as effective as required to maintain leakage within permissible limits.The primary containment penetrations have safety-related components relied upon to remainfunctional during and following DBEs. LRA Table 2.3.2-7 identifies the following primary containment penetrations component typeswithin the scope of license renewal and subject to an AMR:
* bolting
* piping
* valve bodyThe intended function of the primary containment penetrations is to provide a pressureboundary.2.3.2.7.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.7 and UFSAR Sections 5.2.2, 5.2.3.4, and 5.2.3.5 usingthe evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.2.7.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the primary containment penetrations components within the scope of 2-60license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by10 CFR 54.21(a)(1).2.3.3  Auxiliary SystemsIn LRA Section 2.3.3, the applicant identified the SCs of the auxiliary systems subject to anAMR for license renewal.The applicant described the supporting SCs of the auxiliary systems in the following LRA sections:
* 2.3.3.1standby liquid control
* 2.3.3.2service water
* 2.3.3.3reactor building closed cooling water
* 2.3.3.4emergency diesel generator
* 2.3.3.5fuel pool cooling
* 2.3.3.6fuel oil
* 2.3.3.7instrument air
* 2.3.3.8fire protection-water
* 2.3.3.9fire protection-carbon dioxide
* 2.3.3.10heating, ventilation and air conditioning
* 2.3.3.11primary containment atmosphere control/containment atmospheredilution
* 2.3.3.12John Deere diesel
* 2.3.3.13miscellaneous systems in-scope for 10 CFR 54.4(a)(2)The staff's review findings regarding LRA Sections 2.3.3.1 - 2.3.3.13 are presented in SERSections 2.3.3.1 - 2.3.3.13, respectively.2.3.3.1  Standby Liquid Control2.3.3.1.1  Summary of Technical Information in the Application LRA Section 2.3.3.1 describes the SLC system, which, independent of the control rods, shutsdown the reactor from full power and maintains the reactor subcritical during cooldown.
Maintaining subcriticality as the nuclear system cools assures that the fuel barrier is not threatened by overheating if not enough control rods can be inserted to counteract the positive reactivity effects of a colder moderator. The system, located in the reactor building, consists of a boron solution tank, a test water tank, two positive-displacement pumps, two explosive valves, an ion exchanger, a flush pump, piping, and valves. The liquid is pumped into the reactor vessel and discharged near the bottom of the core shroud to mix with the cooling water rising through the core.
2-61The SLC system has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related SSCs in the SLC system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the SLC system performs functions that support ATWS.LRA Tables  2.3.3-1 and 2.3.3-13-40 identify the following SLC system component types withinthe scope of license renewal and subject to an AMR:
* bolting
* gauge
* heater
* orifice
* piping
* pump casing
* sight glass
* strainer housing
* tank
* thermowell
* tubing
* valve bodyThe SLC system component intended function within the scope of license renewal is to providea pressure boundary.2.3.3.1.2  Staff Evaluation The staff reviewed LRA Sections 2.3.3.1 and 2.3.3.13, and UFSAR Section 3.8 using theevaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.1.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any components subject to an AMR.
The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the SLC system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-622.3.3.2  Service Water2.3.3.2.1  Summary of Technical Information in the Application LRA Section 2.3.3.2 describes the SW system and the RHRSW system. The purpose of theSW system is to provide cooling water to various normal and emergency operating loads. The SW system consists of two parallel headers which supply cooling water to the following turbine and reactor auxiliary equipment: a reactor building closed cooling water (RBCCW) heat exchanger, RHR corner room ventilation coolers, a DG cooler, and an RHR heat exchanger (via the RHRSW pumps and piping). Each header is supplied by two pumps. The standby fuel pool cooling (SBFPC) system normally is supplied from the SW Train B header. The header and cross tie can be configured to be fed from the A header with B secured. Other turbine and reactor auxiliary equipment is supplied from a line tied into both headers. The purpose of the RHRSW system is to transfer heat from the RHR system during normal operation and accident conditions. The RHRSW system consists of four RHRSW pumps, two RHR heat exchangers and piping, valves, and instrumentation necessary to ensure system operation. The RHRSW pumps are supplied from the SW system. The cooling water then is pumped through the RHR heat exchangers and returned to the SW system.The SW and RHRSW systems have safety-related components relied upon to remain functionalduring and following DBEs. The failure of nonsafety-related SSCs in the system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the systems perform functions that support fire protection.LRA Tables  2.3.3-2, 2.3.3-13-34, and 2.3.3-13-42 identify the following SW and RHRSWsystem component types within the scope of license renewal and subject to an AMR:
* bolting
* coil
* expansion joint
* fan housing
* heat exchanger (bonnet)
* heat exchanger (shell)
* heat exchanger (tubes)
* heat exchanger (tubesheets)
* indicator
* orifice
* piping
* pump casing
* strainer
* strainer housing
* suction barrel
* thermowell
* tubing
* valve body 2-63The component intended functions within the scope of license renewal include the following:
* flow control
* filtration
* heat transfer
* pressure boundary
* structural or functional support for safety-related equipment2.3.3.2.2  Staff Evaluation The staff reviewed LRA Sections 2.3.3.2 and 2.3.3.13, and UFSAR Sections 10.6, 10.7, and10.8 using the Tier-2 evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.2 identified areas in which additional information wasnecessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.The staff noted that license renewal drawing LRA-G-191159-SH-01-0, at location H-12, depictspipe section 2"-SW- 566C within the scope of license renewal. Upstream from where 2"-SW-566C enters the reactor building from the outside, there is no drawing continuation to depict the license renewal boundary. In RAI 2.3.3.2a-1 dated August 16, 2006, the staff requested that the applicant provide information for the continuation of 2"-SW-566C to the license renewal boundary and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). In its response dated September  20, 2006, the applicant stated that pipe section 2"-SW-566Ccontains vacuum breakers to prevent water-hammer in the nonsafety-related portion of the SW system. The portion of this piping outside of the reactor building wall ends at this point. There is no continuation of this portion of the piping.Based on its review, the staff found the applicant response to RAI 2.3.3.2a-1 acceptablebecause the applicant confirmed this section of piping ends outside the reactor building wall and does not continue on another drawing. This is a section of piping open to atmosphere immediately outside of the reactor building to allow air flow to the vacuum breakers depicted on pipe section 2"-SW-566C. Therefore, the staff concern described in RAI 2.3.3.2a-1 is resolved.The staff noted that license renewal drawing LRA-G-191159-SH-01-0, at location H-11, drawingnote 16 indicates pipe section 4"-SW-567 and its supports on the reactor building alternate cooling supply piping (where the vacuum breakers tie in) are seismic Class II for structural integrity. This pipe section from valve 23D through valves RBAC-1A, 1B, 1C and 1D is not 2-64shown within the scope of license renewal. Failure of this pipe could have an adverse effect onthe intended pressure boundary function for the service water piping. In RAI 2.3.3.2a-2 dated August 16, 2006, the staff requested that the applicant provide additional information about why this section of pipe and components are not shown within the scope of license renewal and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). In its response dated September  20, 2006, the applicant stated that this portion of piping isincluded for 10 CFR 54.4(a)(2) since it provides structural support for the safety-related portion of the system. As described in LRA Section 2.1.2.1.3, portions of systems included as required by 10 CFR 54.4(a)(2) are not shown on license renewal drawings. However, as discussed in LRA Table 2.3.3.1 3-8 for the SW system, the components outside the safety class pressure boundary, while relied upon to provide structural/seismic support for the pressure boundary are in-scope and subject to an AMR. This includes the portion of line 4"-SW-567 required to provide structural support for the vacuum breakers. In addition, this piping and associated valves are included as required by 10 CFR 54.4(a)(2) due to spatial interaction from spray or leakage since the line is in the reactor building.Based on its review, the staff found the applicant response to RAI 2.3.3.2a-2 acceptablebecause the applicant acknowledged this section of piping 4" SW-567 from valve 23D to RBAC-1A, 1B, 1C, and 1D is within the scope of license renewal. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Although the applicant did not identify this section of piping as being within the boundary of license renewal on the drawing, the applicant confirmed it is within the scope based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). Therefore, the staff concern described in RAI 2.3.3.2a-2 is resolved.The staff noted license renewal drawing LRA-G-191159-SH-01-0, at location D-5, depicts thelicense renewal boundary on the downstream side of flow control valve (FCV)-104-17A. The pipe section from FCV-104-17A to the safety class boundary designation flag located at valve 171A and to the intake screens is not shown within the scope of license renewal. Similarly, the pipe section from FCV-104-17 B, C, D, and E to valves 17B, C, D and E and to the intake screens is also not shown within the scope of license renewal. Failure of these sections of pipe could have an adverse effect on the intended pressure boundary function for the service water piping. In RAI 2.3.3.2a-3 dated August 16, 2006, the staff requested that the applicant provide additional information about why these sections of piping and components are not shown within the scope of license renewal and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a).In its response dated September 20, 2006, the applicant stated that the license drawings onlyshow the portions of the system with intended functions that meet the requirements of 10 CFR 54.4(a)(1) or (a)(3). As described in LRA Section 2.1.2.1.3, portions of systems included as required by 10 CFR 54.4(a)(2) are not shown on license renewal drawings. Valves FCV-104-17A/B/C/D and E are normally closed valves that are only open when the traveling screens are being washed. Providing water to clean the screens is not a function that meets the requirements of 10 CFR 54.4(a)(1) or (a)(3). These valves fail to a closed position such that failure of the piping downstream of these valves would not affect the ability of the SW system to perform its functions as required by 10 CFR 54.4(a)(1) or (a)(3). However, as described in LRA Table 2.3.3.13-B, the portion of the SW system in the intake structure near the SW pumps and 2-65the components outside the safety class pressure boundary, while relied upon to providestructural/seismic support for the pressure boundary are in-scope and subject to an AMR as required by 10 CFR 54.4(a)(2). This includes the portion of lines downstream of FCV-104-17A/B/C/D and E that provide structural support. Based on its review, the staff found the applicant response to RAI 2.3.3.2a-3 acceptablebecause the applicant acknowledged these sections of piping are within the scope of license renewal. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Although the applicant did not identify these sections of piping as being within the boundary of license renewal on the drawing, the applicant confirmed they are within the scope based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). Therefore, the staff concern described in RAI 2.3.3.2a-3 is resolved.The staff noted that license renewal drawing LRA-G-191159-SH-02-0, at location G-6, depicts alicense renewal boundary flag at the tee of pipe sections 2"-SW-566D and 8"-SW-34. There are no highlighted pipes or components on 2"-SW-566D or 8"-SW-34. In RAI 2.3.3.2a-4 dated August 16, 2006, the staff requested that the applicant clarify which portions of pipe and components are and are not bounded by the aforementioned boundary flag and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). In its response dated September 20, 2006, the applicant stated license renewal drawings onlyshow the portions of the system with intended functions that meet the requirements of 10 CFR 54.4(a)(1) or (a)(3). As described in LRA Section 2.1.2.1.3, portions of systems included as required by 10 CFR 54.4(a)(2) are not shown on license renewal drawings. The piping and valves on line 2"-SW- 566D are safety-related, since they have a safety function to break vacuum and prevent water hammer in the SW system. As a result, a system intended function boundary flag is provided that points towards and includes all the components on line 2"-SW-566D. The reason these components are not highlighted as subject to an AMR is that they perform their system intended function though the active function of the valves opening and breaking vacuum. In accordance with 10 CFR 54.21 (a)(1)(i), components that perform their intended functions with moving parts or a change in configuration are not subject to an AMR. These components do not have a passive intended function of pressure boundary as required by 10 CFR 54.4(a)(1) or (a)(3), since this portion of the system is isolated when aligned to the ultimate heat sink. However, as described in LRA Table 2.3.3.13-6, the portion of the SW system inside the reactor building and the components outside the safety class pressure boundary, while relied upon to provide structural/seismic support for the pressure boundary are in-scope and subject to an AMR as required by 10 CFR 54.4(a)(2). This includes line 2-SW-566D and portions of lines connected to this line that provide structural support and have the potential to affect safety-related components due to spray or leakage. Based on its review, the staff found the applicant response acceptable because the applicantacknowledged that pipe 2" SW-566D is within the scope of license renewal and subject to an AMR based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Therefore, the staff concern described in RAI 2.3.3.2a-4 is resolved.
2-66The staff's review of LRA Section 2.3.3.2 identified areas in which information provided in theLRA needed to be confirmed by the NRC Regional Inspection Team to complete the review of the applicant's scoping and screening results.Inspection Item 2.3.3.2a-1License renewal drawing LRA-G-191159-SH-01-0, at location H-11, depicts pipesection 2"-SW-566C as within the scope of license renewal. The license renewal boundary flag for 2"-SW-566C is located on an unisolable section of pipe. The actual location of the license renewal scope boundary for this pipe section is not clear. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components meet the requirements of 10 CFR 54.4(a)(2).In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRCLicense Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the regional inspection team stated in part that the applicant has included in-scope for spatial interaction the portion of the SW system in the service water pump area of the intake structure and the reactor building. Pipe section 2" SW-566C is in the reactor building and is therefore in-scope for spatial interaction. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Further, the applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 indicates that pipe section 4"SW-567 which attaches to pipe section 2" SW-566C is in-scope for spatial interaction.Based on its review, the staff found the above response acceptable because the inspectionteam and the applicant acknowledged that service water pipe 2" SW-566C is within the scope of license renewal and subject to an AMR based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). Therefore, the staff concern described in Inspection Item 2.3.3.2a-1 is resolved.Inspection Item 2.3.3.2a-2LRA Section 2.1.2.1.2 states in part that nonsafety-related piping systems connected tosafety-related systems were included up to the structural boundary or to a point that includes an adequate portion of the nonsafety-related piping run to conservatively include the first seismic or equivalent anchor. In addition, if isometric drawings were not readily available to identify the structural boundary, connected lines were included to a point beyond the safety/nonsafety interface, like a base-mounted component, flexible connection, or the end of a piping run (i.e , adrain line). The staff cannot determine whether all the nonsafety-related piping systems were included upto the structural boundary or to a point that includes an adequate portion of the nonsafety-related piping run to include the first seismic or equivalent anchor. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(2).
2-67In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRCLicense Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated in part that for structural support considerations, the applicant has included components outside the safety class pressure boundary, yet relied upon to provide structural/seismic support for the pressure boundary. The application describes the types of components which are included in the scope of license renewal for 10 CFR 54.4(a)(2) and subject to an AMR in the service water system in LRA Table 2.3.3-13-42. This table was developed by including all nonsafety-related portions of fluid systems which are located within a building containing safety-related components and all nonsafety-related piping connected to safety-related systems back to the structural boundary using an isometric drawing. In cases where an isometric drawing which depicts the structural boundary is not readily available, connected lines were included back to a point beyond the safety/nonsafety interface to a base-mounted component, flexible connection, or the end of a piping run (such as a drain line) in accordance with the response to RAI 2.1-2. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Further, the applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2states that there are no nonsafety-related systems for which the applicant has not identified the nonsafety-related portions of systems which are attached to safety-related systems and required to be in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). However, as a result of discussions with the staff during the Region I inspection (February 2007), the applicant determined that some safety-related SSCs in the VY turbine building required consideration for potential spatial impacts from nonsafety-related SSCs based on 10 CFR 54.4(a)(2). Therefore, an expanded review for SSCs in the turbine building determined that additional components required an AMR. Those additional component types have been added to LRA Table 2.3.3-13-42, as addressed in the applicant's letters to the NRC dated July 30, 2007 and August 16, 2007. Based on its review, the staff found the above response acceptable because the applicantstated that there are no nonsafety-related portions of systems which are attached to safety-related systems that are not within the scope of license renewal in accordance with 10 CFR 54.4(a)(2), but that there were spatial impact concerns from nonsafety-related SSCs in the turbine building. The additional component types have been added to LRA Table 2.3.3-13-42. Therefore, the staff concern described in Inspection Item 2.3.3.2a-2 is resolved.2.3.3.2.3  Conclusion The staff reviewed the LRA, accompanying license renewal drawings, and RAI and inspectionitem responses to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the SW and RHRSW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-682.3.3.3  Reactor Building Closed Cooling Water2.3.3.3.1  Summary of Technical Information in the Application LRA Section 2.3.3.3 describes the RBCCW system, which supplies demineralized water to thereactor building auxiliary equipment systems from a closed cooling loop. The RBCCW system cools equipment which may contain radioactive fluids. The SW system provides the heat sinkfor the RBCCW system. The RBCCW cooling function is not a safety function. FPC is not a safety function of RBCCW since the safety-related SBFPC system uses SW as a heat sink.
RBCCW supplies the heat sink for the nonsafety-related FPC system. RHR pump seal cooling is normally provided by RBCCW, not SW. This is not a safety function for RBCCW because RHR pump seal cooling is not required to support hot safe shutdown. However, if the SW pumps are inoperable and alternate cooling is inservice, the RHR pump seal coolers are manually aligned to the SW supplied by the ACS. In accordance with these conditions (loss of Vernon Pond, flooding of the SW intake structure, or fire in the SW intake structure which disables all four SW pumps), RHR pump seal cooling is a safety function of SW via ACS and the RBCCW system piping, which provides for seal cooling to be supplied by ACS and performs the safety function of maintaining SW system integrity.The RBCCW system has safety-related components relied upon to remain functional duringand following DBEs. The failure of nonsafety-related SSCs in the RBCCW system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the RBCCW system performs functions that support fire protection.LRA Tables  2.3.3-3 and 2.3.3-13-30 identify the following RBCCW system component typeswithin the scope of license renewal and subject to an AMR:
* bolting
* flow switch housing
* heat exchanger (housing)
* heat exchanger (shell)
* heat exchanger (tubes)
* piping
* pump casing
* sight glass
* strainer housing
* tank
* thermowell
* tubing
* valve bodyThe RBCCW system component intended functions within the scope of license renewal includethe following:
* pressure boundary
* structural or functional support for safety-related equipment 2-692.3.3.3.2  Staff EvaluationThe staff reviewed LRA Section 2.3.3.3 and UFSAR Section 10.9 using the Tier-2 evaluationmethodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.3 identified an area in which additional information wasnecessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.The staff noted that license renewal drawing LRA-G-191159-SH-03-0, at location P-10 at valve29 shows a section of pipe within the scope of license renewal. This section of pipe is the RBCCW return to the ACS. However, a drawing continuation is not provided. In RAI 2.3.3.3-1 dated August 16, 2006, the staff requested that the applicant provide information for the continuation of this piping section to the license renewal boundary and justify the boundary location with respect to the applicable requirements of 10 CFR 54.4(a).In its response dated September 20, 2006, the applicant stated that the RBCCW return to theACS shown on license renewal drawing LRA-G-191159-SH-03-0, at location P-10 at valve 29 continues on license renewal drawing LRA-G-191159-SH-02-0, at location E-2.Based on its review, the staff found the applicant response to RAI 2.3.3.3-1 acceptablebecause the applicant provided the necessary drawings and documentation to demonstrate this section of reactor building closed cooling water piping was connected to the service water system, was identified as being within the scope of license renewal, and with boundaries correctly identified on the service water system flow diagram, LRA-G-191159-SH-2-0.
Therefore, the staff concern described in RAI 2.3.3.3-1 is resolved.2.3.3.3.3  Conclusion The staff reviewed the LRA, accompanying license renewal drawings, and RAI responses todetermine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the RBCCW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-702.3.3.4  Emergency Diesel Generator2.3.3.4.1  Summary of Technical Information in the Application LRA Section 2.3.3.4 describes the EDG and the diesel lube oil (DLO) systems. The purpose ofthe DG system is to provide Class 1E electrical power to the emergency buses in a loss of normal power condition or a LOCA coincident with loss of normal power or degraded grid voltage at the emergency buses and is available to provide Class 1E electrical power to the emergency buses in a LOCA with normal power available. The DG and auxiliary systems will start and be in standby during a LOCA. The purpose of the DLO system is to provide for DLO storage and provide for prelube of the DGs. The DLO system consists of two lube oil day tanks and pre-lube oil pumps only. The DLO system in the component database has only these four components. The remaining components supplying lube oil required during EDG operation are in the DG system.The DG and DLO systems have safety-related components relied upon to remain functionalduring and following DBEs. The failure of nonsafety-related SSCs in the system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the systems perform functions that support fire protection.LRA Tables  2.3.3-4, 2.3.3-13-10, and 2.3.3-13-11 identify the following EDG system, DG andauxiliaries system, and DLO system component types within the scope of license renewal and subject to an AMR:
* bolting
* expansion joint
* filter housing
* heat exchanger (bonnet)
* heat exchanger (fins)
* heat exchanger (shell)
* heat exchanger (tubes)
* heat exchanger (tubesheets)
* heater housing
* orifice
* piping
* pump casing
* sight glass
* silencer
* strainer
* strainer housing
* tank
* thermowell
* tubing
* turbocharger
* valve body 2-71The component intended functions within the scope of license renewal include the following:
* flow control
* filtration
* heat transfer
* pressure boundary2.3.3.4.2  Staff Evaluation The staff reviewed LRA Sections 2.3.3.4 and 2.3.3.13, and UFSAR Section 8.5 using the Tier-2evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).In letters to the NRC dated July 30, 2007 and August 16, 2007, the applicant reported thedeletion of DG compressor housing from LRA Table 2.3.3-13-10 as a component type subject to an AMR. The applicant stated that since the compressor housing will not contain liquid, it should not be subject to an AMR for potential spatial interaction. The staff has reviewed this component type deletion and concurs that the deletion of the DG compressor housing is acceptable.2.3.3.4.3  Conclusion The staff reviewed the LRA, accompanying license renewal drawings, and RAI responses todetermine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the EDG system, DG and auxiliaries system, and DLO system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.5  Fuel Pool Cooling2.3.3.5.1  Summary of Technical Information in the Application LRA Section 2.3.3.5 describes the FPC system, the safety-related SBFPC subsystem, the fuelpool filter-demineralizer (FPFD) system, and the Boral in the spent fuel racks. The FPC system removes the decay heat released from the spent fuel elements. During normal operation, the system maintains a specified fuel pool water temperature, purity, water clarity, and water level.
The system cools the fuel storage pool by transferring the spent fuel decay heat through heat exchangers to the RBCCW. The purpose of the SBFPC system is to maintain pool temperature during design basis accidents (including concurrent LOCAs, loss of offsite power, and single failure) or if an unusually high spent fuel decay heat load is placed in the pool. The purpose of 2-72the FPFD is to maintain the purity of the spent fuel pool water by minimizing corrosion productbuildup and controlling water clarity, minimizing fission product contamination in the water, and controlling removal of water from the fuel pool to the CST system. Boral sheets in the spent fuel storage pool provide neutron absorption.The FPC and SBFPC systems have safety-related components relied upon to remain functionalduring and following DBEs. The failure of nonsafety-related FPC, SBFPC, and FPFD systems SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the FPC and SBFPC systems perform functions that support fire protection.LRA Tables  2.3.3-5, 2.3.3-13-16, 2.3.3-13-17, and 2.3.3-13-37 identify the following FPC,FPFD, and SBFPC system component types within the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* heat exchanger (shell)
* heat exchanger (tubes)
* neutron absorber (boral)
* orifice
* piping
* pump casing
* thermowell
* tubing
* valve bodyThe component intended functions within the scope of license renewal include the following:
* heat transfer
* neutron absorption
* pressure boundary2.3.3.5.2  Staff Evaluation The staff reviewed LRA Sections 2.3.3.5 and 2.3.3.13, and UFSAR Sections 10.3 and 10.5using the Tier-2 evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).
2-73The staff's review of LRA Section 2.3.3.5 identified an area in which additional information wasnecessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.The staff noted that license renewal drawing G-191173, Sheet 1, at location H-5 shows asection of pipe within the scope of license renewal. The section of pipe includes check valve V-30 and a "penetration at concrete wall," with changes in seismic classifications at each end.
The section of pipe is isolated from all other in-scope piping and is not in an in-scope flow path.
Piping upstream of V-30 (8"-FPC-24, 6"-FPC-24, and 8"-FPC-34) contains two normally closed valves (V-28 and V-53) and is not shown within the scope of license renewal. Piping downstream of V-30 (4"-FPC-24 and 4"-FPC-25) is also not shown within the scope of license renewal. Failure of these sections of piping could have an adverse effect on the intended pressure boundary function for the FPC piping. In RAI 2.3.3.5a-1 dated August 16, 2006, the staff requested that the applicant provide information to justify exclusion from the scope of license renewal the piping from valves V-28 and V-53 to valve V-30 and from the reactor well diffusers to the current license renewal boundary at the penetration upstream of valve V-30.In its response dated September  20, 2006, the applicant stated that license renewal drawingsonly show the portions of the system with intended functions that meet the requirements of 10 CFR 54.4(a)(1) or (a)(3). As described in LRA Section 2.1.2.1.3, portions of systems required by 10 CFR 54.4(a)(2) are not shown on license renewal drawings. The piping from valves V-28 and V-53 to valve V-30 and from the reactor well diffusers to the license renewal boundary at the penetration upstream of valve V-30 are within the scope of license renewal and subject to an AMR as required by 10 CFR 54.4(a)(2) and as described in LRA Table 2.3.3.13-B for the FPC system. The description includes portions of the system in the primary containment building and reactor building and components outside the safety class pressure boundary which are relied upon to provide structural/seismic support for the pressure boundary. The piping in question is inside the reactor building and attached to safety-related components so it is within the scope of license renewal and subject to an AMR.Based on its review, the staff found the applicant response to RAI 2.3.3.5a-1 acceptablebecause the applicant acknowledged that piping from valves V-28 and V-53 to valve V-30 and from the reactor well diffusers to the license renewal boundary at the penetration upstream of valve V-30 are included within the scope of license renewal. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Although the applicant did not identify these sections of piping within the boundary of license renewal on the drawing, the applicant confirmed they are within the scope of license renewal based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). Therefore, the staff concern described in RAI 2.3.3.5a-1 is resolved.
2-742.3.3.5.3  ConclusionThe staff reviewed the LRA, accompanying license renewal drawings, and RAI response todetermine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the FPC, FPFD, and SBFPC system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.6  Fuel Oil2.3.3.6.1  Summary of Technical Information in the Application LRA Section 2.3.3.6 describes the fuel oil (FO) system, which supplies FO to the EDGs as wellas the nonsafety-related diesel-driven fire pump, John Deere diesel (JDD), and house HB. The portion of the system related to the EDGs consists of a day tank and fuel transfer pump for each diesel, the FO storage tank, valves, and piping. The diesel fire pump FO day tank, JDD day tank, and house HB FO storage tank are not connected to the FO storage tank. Normal makeup to the house HB FO storage tank is by tanker truck. Normal makeup to the diesel fire pump FO day tank and JDD day tank is from a 500-gallon portable tank filled from the FO storage tank.The FO system has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related SSCs in the FO system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the FO system performs functions that support fire protection.LRA Tables  2.3.3-6 and 2.3.3-13-14 identify the following FO system component types withinthe scope of license renewal and subject to an AMR:
* bolting
* filter housing
* flame arrestor
* flex hose
* injector housing
* piping
* pump casing
* sight glass
* strainer housing
* tank
* thermowell
* tubing
* valve body
* strainer housing 2-75The FO system component intended functions within the scope of license renewal include thefollowing:
* flow control
* pressure boundary2.3.3.6.2  Staff Evaluation The staff reviewed LRA Sections 2.3.3.6 and 2.3.3.13, and UFSAR Section 8.5.4 using theTier-2 evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.6 identified an area in which additional information wasnecessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.The staff noted that license renewal drawing LRA-G-191162, Sheet 2, provides informationabout the EDGs, diesel-driven fire pump, and house HB systems, supported by the FO system.
However, the drawing does not provide sufficient information about the JDD system, also supported by the FO system. For example, more information is required regarding the transfer system between the 75,000-gallon FO storage tank, the day tanks for the two JDDs, and single fire pump diesel, which is necessary to provide an intended function in accordance with 10 CFR 54.4 (a)(3) in support of the fire protection regulation requirements (10 CFR 50.48).
The LRA text states only that a 500-gallon portable tank is used to transport FO to the diesel day tanks. Typical components subject to an AMR for diesels like the day tank, strainer, etc., for the JDDs are not covered. In RAI 2.3.3.6-1 dated August 16, 2006, the staff requested that the applicant provide FO system drawings and describe the JDD system. The staff also requested that the applicant explain the relationship between the JDD and the FO systems and clarify what the AMR tables should include in both Sections 2.3.3.6 and 2.3.3.12. The staff further requested that the applicant also provide information for the license renewal boundary that justifies its location with respect to the applicable requirements of 10 CFR 54.4(a).In its response dated September  20, 2006, the applicant stated that the 350-gallon diesel firepump FO day tank and 550-gallon fiberglass underground storage tank for the JDD are filled with FO from the FO storage tank. The FO is pumped from the FO storage tank drain line into a portable 500-gallon tank. The portable tank is then moved to the intake structure or JDD building by a fork lift. A 12VDC pump on the portable tank then pumps the FO into the diesel fire pump FO day tank or the fiberglass underground storage tank for the JDD. Since the portable tank and pump are not part of the FO system pressure boundary and since levels in the diesel fire pump FO day tank and underground storage tank for the JDD are maintained, the portable tank and pump do not perform a component intended function and are not subject 2-76to an AMR. A dedicated 550-gallon fiberglass underground storage tank provides fuel to theJDD engine. As the JDD is required for compliance with the staff's regulations concerning fire protection (10 CFR 50.48), providing FO for the engine is an intended function of the FO system in accordance with 10 CFR 54.4 (a)(3). Therefore, the storage tank and associated piping and components that supply FO to the diesel engine injectors are within the scope of license renewal and subject to an AMR. JDD FO components are included in LRA Tables  2.3.3.6 and 3.3.2-6. As the JDD is required for compliance with the staff's regulations concerning fire protection (10 CFR 50.48), it is within the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 (a)(3). The passive mechanical components of the diesel subject to an AMR that were confirmed by walkdown are included in LRA Tables  2.3.3-12 and 3.3.2-12. Based on its review, the staff found the applicant response to RAI 2.3.3.6-1 acceptablebecause the applicant explained that the 550-gal fiberglass underground storage tank and associated piping and components that supply FO to the diesel engine injectors are within thescope of license renewal and an AMR. The applicant stated that flow diagrams are not available for this skid-mounted diesel, or its FO system, and only a few components are represented in the equipment database. The applicant, however, has verified by walkdown of the system that these passive components are identified in AMR Tables 2.3.3-12 and 3.3.2-12. Therefore, the staff concern described in RAI 2.3.3.6-1 is resolved.2.3.3.6.3  Conclusion The staff reviewed the LRA, accompanying license renewal drawings, and RAI response todetermine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the FO system components within the scope of license renewal, as required by 10 CFR 54.4(a),
and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.7  Instrument Air2.3.3.7.1  Summary of Technical Information in the Application LRA Section 2.3.3.7 describes the IA, SA, 105 (IA and SA instruments), and nitrogen (N 2)supply systems. The purpose of the IA system is to provide the station continuously with dry, oil-free air for pneumatic instruments and controls through a dual header system. The IA system includes the containment N 2 supply described in the UFSAR as a separate N 2subsystem also known as containment air. The purpose of containment N 2 is to providepneumatically-operated components in the drywell with N 2 when the primary containment isinerted so any component leakage will not dilute the N 2 atmosphere. This N 2 source can befrom either the N 2 system (normal supply) or the containment air compressor (automatic backupsupply). When neither N 2 supply is available or when the containment is not inerted, IA may belined up manually as a secondary backup for the containment N
: 2. When the containment is notinerted, IA will be lined up as the primary source of pneumatic pressure.
2-77The purpose of the SA system is to provide the station with the compressed air requirementsfor pneumatic instruments and controls and general station services. The IA system also supports this function. The purpose of the 105 system is to provide indication, alarm, and control functions for associated systems. This code is used in the component database for various instrumentation components related to IA and SA. Although the 105 system consists mainly of EIC components, certain IA instrumentation mechanical components are included as well. The purpose of the N 2 system is to provide N 2 gas to the primary containment atmosphericcontrol (PCAC) system to satisfy the primary containment purge and normal make-up requirements.The IA, SA, 105, and N 2 systems have safety-related components relied upon to remainfunctional during and following DBEs. The failure of nonsafety-related SSCs in the IA and N 2system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the IA system performs functions that support fire protection and SBO.LRA Tables 2.3.3-7, 2.3.3-13-54, 2.3.3-13-22, and 2.3.3-13-24 identify the following IA, SA and N 2 system component types within the scope of license renewal and subject to an AMR:
* bolting
* piping
* strainer housing
* tank
* trap
* tubing
* valve bodyThe IA, SA and N 2 system component intended function within the scope of license renewal isto provide a pressure boundary.2.3.3.7.2  Staff Evaluation The staff reviewed LRA Sections 2.3.3.7 and 2.3.3.13, and UFSAR Section 10.14 using theTier-2 evaluation methodology, for IA and N 2, and the Tier-1 methodology, for SA and 105systems, described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).In letters to the NRC dated July 30, 2007 and August 16, 2007, the applicant reported thedeletion of IA compressor housing from LRA Table 2.3.3-13-22 as a component type subject to an AMR. The applicant stated that since the compressor housing will not contain liquid, it should not be subject to an AMR for potential spatial interaction. The staff has reviewed this component type deletion and concurs that the deletion of the IA compressor housing is acceptable.
2-782.3.3.7.3  ConclusionThe staff reviewed the LRA and accompanying license renewal drawings to determine whetherthe applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the IA and N 2systems components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.8  Fire Protection-Water2.3.3.8.1  Summary of Technical Information in the Application LRA Section 2.3.3.8 describes the fire protection-water system. The fire protection systemprovides fire protection for the station through the use of water, CO 2, dry chemicals, foam,detection and alarm systems, and rated fire barriers, doors, and dampers. Water for the fire protection system is from two vertical turbine-type pumps, one electric motor-driven and one diesel-driven. The pumps and drivers located in the intake structure discharge to an underground piping system serving the exterior and interior fire protection systems. The pressure in the system is maintained at approximately 100 psig by an interconnection to the SW system. A check valve in the connecting pipe prevents backflow. Through an interconnecting valve, the SW system can provide water to fire protection components in the unlikely event that both fire protection pumps are unavailable.The failure of nonsafety-related SSCs in the fire protection-water system potentially couldprevent the satisfactory accomplishment of a safety-related function. The fire protection-water system also performs functions that support fire protection.LRA Tables 2.3.3-8 and 2.3.3-13-15 identify the following fire protection-water systemcomponent types within the scope of license renewal and subject to an AMR:
* bolting
* expansion joint
* filter
* filter housing
* flow nozzle
* gear box
* heat exchanger (bonnet)
* heat exchanger (shell)
* heat exchanger (tubes)
* heater housing
* nozzle
* orifice
* piping
* pump casing
* silencer
* strainer
* strainer housing 2-79
* tank
* tubing
* turbocharger
* valve bodyIn LRA Table 3.3.2-8, the applicant provides the results of the AMR.
The fire protection-water system component intended functions within the scope of licenserenewal include the following:
* flow control
* filtration
* heat transfer
* pressure boundary2.3.3.8.2  Staff Evaluation The staff reviewed LRA Sections 2.3.3.8 and 2.3.3.13, and UFSAR Section 10.11 using theevaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).The staff also reviewed the VYNPS fire protection SER, dated January 13, 1978, andsupplemental SERs listed in the VYNPS Operating License Condition g.3.F. These reports are referenced in the VYNPS fire protection CLB and summarize the fire protection program and commitments required by 10 CFR 50.48 using BTP Auxiliary and Power Conversion Systems Branch (APCSB) 9.5-1, ?Guidelines for Fire Protection for Nuclear Power Plants," May 1, 1976,and Appendix A to BTP APCSB 9.5-1, August 23, 1976. The staff then reviewed those components that the applicant identified as being within the scope of license renewal to verify that the applicant did not omit any passive and long-lived components that should be subject to an AMR as required by 10 CFR 54.21(a)(1). The staff's review of LRA Section 2.3.3.8 identified areas requiring additional informationnecessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.3.8-1, dated August 15, 2006, the staff stated that LRA drawingLRA-G-191163-SH-02-0, "Fire Protection System Outer Loop," shows the yard fire hydrants as out of scope (i.e., not colored in purple). The staff requested that the applicant verify whether the yard fire hydrants are in-scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and not subject to an AMR, the staff requested that the applicant provide justification for the exclusion.
2-80In its response, by letter dated September  20, 2006, the applicant stated:LRA drawing LRA-G-191163-SH-02-0, "Fire Protection System Outer Loop"shows that the yard fire hydrants are not subject to an AMR since they are not highlighted.As described in LRA Section 2.3.3.8:
The fire protection-water system has no intended functions as required by10 CFR 54.4(a)(1).The fire protection-water system intended functions as required by10 CFR 54.4(a)(2) include the following:
* Maintain integrity of nonsafety-related components such that no physical interaction with safety-related components could prevent satisfactory accomplishment of a safety function.The fire protection-water system intended functions as required by10 CFR 54.4(a)(3) include the following:
* Provide the capability to extinguish fires in vital areas of the plant(10 CFR 50.48).Therefore, the fire protection system is in-scope for license renewal. The piping in the outer loop performs a component pressure boundary intendedfunction that supports the ability of the fire protection system to extinguish fires in vital areas of the plant serviced by the inner loop. If the outer loop failed, piping that provides water to fire systems in vital areas of the plant may not perform its intended function. The yard fire hydrants are isolable from the outer loop such that their failure would not impact the support of vital areas. Yard fire hydrants are not required to extinguish fires in vital areas of the plant and their failure cannot impact safety-related components. Therefore, the yard fire hydrants perform no intended function in support of the system intended functions and are not subject to an aging management review. In evaluating this response, the staff found that it was incomplete and that review of LRASection 2.3.3.8 could not be completed. Yard fire hydrants are included in-scope of license and excluded from an AMR. The staff finds this contrary to the original VYNPS fire protection safety evaluation (SE) and UFSAR as the CLB. In its response, the applicant stated that the yard fire hydrants perform no intended function in support of the system intended functions and are not subject to an AMR and therefore, not credited in accordance with 10 CFR 50.48. This resulted in the staff holding a telephone conference with the applicant on November 7, 2006, to discuss information necessary to resolve the concern in RAI 2.3.3.8-1. The staff explained that the scope of SSCs required for compliance with 10 CFR 50.48 and 10 CFR 50 Appendix A, GDC 3, 2-81goes beyond preserving the ability to maintain safe-shutdown in the event of a fire. The staffstated that the exclusion of fire protection SSCs, on the basis that the intended function is not required for the protection of safe-shutdown equipment or safety-related equipment is not acceptable, if the SSC is required from compliance with 10 CFR 50.48.By letter dated December 4, 2006, the applicant stated that the yard fire hydrants are in-scopeand subject to an AMR. The hydrants are identified as component type "valve body" in LRA Table 2.3.3-8. Results of the AMR are provided in LRA Table 3.3.2-8 for line items "valve body" with carbon steel as the material and raw water as the environment. Based on its review, the staff finds the applicant's response to RAI 2.3.3.8-1 acceptablebecause the applicant has committed to interpret yard fire hydrants as included in the "valve body," which is in the scope for the license renewal and subject to an AMR. The staff is adequately assured that the yard fire hydrants used for the fire suppression will be considered appropriately during the aging management activities. Therefore, the staff's concern described is RAI 2.3.3.8-1 is resolved. In RAI 2.3.3.8-2, dated August 15, 2006, the staff stated that LRA drawing LRA-G-191163-SH-02-0, "Fire Protection System Outer Loop," shows the recirculation pump motor generator set foam system colored in purple (i.e., in-scope). This drawing does not show the 150 gallon foam concentrate tank and its components (piping and valves). The staff requested that the applicant verify whether the 150 gallon foam concentrate tank and its components are in-scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and not subject to an AMR, the staff requested applicant provide justification for the exclusion. In its response, by letter dated September  20, 2006, the applicant stated:LRA drawing LRA-G-191163-SH-01-0, "Fire Protection System Inner Loop"shows the recirculation pump motor generator set foam system colored in purple (i.e., subject to an AMR) at coordinates I/J-2. The associated 150 gallon foam concentrate tank (TK76-1B) and its components are in-scope and subject to an AMR as shown on the same drawing at coordinates B-8. LRA Table 3.3.2.8 includes line items for the tank and associated piping, valves, and flow nozzles with fire protection foam as the internal environment.
2-82Based on its review, the staff found the applicant's response to RAI 2.3.3.8-2 acceptablebecause the recirculation pump motor generator set foam system and the 150 gallon foam concentrate tank and its components (piping and valves) were identified to be in the scope of license renewal and subject to an AMR. Therefore, the staff concludes that this recirculation pump motor generator set foam system and the associated components are correctly included in the scope of license renewal and subject to an AMR. The staff's concern described in RAI 2.3.3.8-2 is resolved.In RAI 2.3.3.8-3, dated August 15, 2006, the staff stated that NRC SE Section 3.2.2, datedJanuary 13, 1978, approving the VYNPS fire protection program, discusses the use of flame retardant coating to protect electrical cables in trays and risers in the switchgear room to meet the requirements of 10 CFR 50.48. The LRA does not list flame retardant coating for cables.
The staff requested that the applicant verify whether the flame retardant coating is in-scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If flame retardant coating is excluded from the scope of license renewal and not subject to an AMR, the staff requested applicant provide justification for the exclusion.In its response, by letter dated September  20, 2006, the applicant stated:Flame retardant (flamemastic) coatings are in-scope and subject to an AMR andare included in the line item "Fire wrap" in LRA Tables 2.4-6 and 3.5.2-6.
Flamemastic was inadvertently omitted from the list of materials for the line item "Fire wrap" in LRA Table 3.5.2-6. Based on its review, the staff found the applicant's response to RAI 2.3.3.8-3 acceptablebecause the applicant states that the fire retardant coating "Flamemastic" was inadvertently omitted from the list of materials for the line item "Fire wrap" in LRA Table 3.5.2-6. Because the applicant has committed to interpret fire retardant coating as included in the line item "Fire wrap," which is in the scope for license renewal and subject to an AMR, the staff is adequately assured that the fire retardant coating used to protect electrical cables in trays and risers will be considered appropriately during plant aging management activities. Therefore, the staff's concern described in RAI 2.3.3.8-3 is resolved. In RAI 2.3.3.8-4, dated August 15, 2006, the staff stated that SE Section 4.3.1(f) discusses amanually-operated foam maker with a permanent storage tank with fire suppression functions in the event of a fire affecting the 75,000 gallon outdoor FO storage tank, the diesel generator day tanks, or the diesel generator room located on the ground floor of the turbine building. The LRA does not list this foam maker and its associated storage tank systems and components. The staff requested that the applicant verify whether the foam maker and storage tank system and components (piping and valves) are in-scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and not subject to an AMR, the staff requested applicant provide justification for the exclusion.In its response, by letter dated September  20, 2006, the applicant stated:As discussed in LRA Section 2.3.3.8, in the turbine building, in addition to hosestations and deluge systems, a foam fire protection agent is available that can be 2-83used to combat fires at the FO storage tank, turbine lube oil storage tank, mainand auxiliary transformers, house HBs, and the emergency diesel generators.The turbine building foam tank (TK76-1A) and associated piping and valves are in-scope andsubject to an AMR as shown on LRA drawing LRA-G-191163-SH-01-0, "Fire Protection System Inner Loop" at coordinates E-8. This manual foam system is used by attaching a fire hose to the outlet and opening valves to enable water from the fire protection header to mix with the foam concentrate from the storage tank and flow through the hose. LRA Table 3.3.2.8 includes line items for the tank and associated piping and valves with fire protection foam as the internal environment. Fire hoses are periodically replaced and managed by the existing fire protection program, andtherefore are not subject to an AMR.Based on its review, the staff found the applicant's response to RAI 2.3.3.8-4 acceptablebecause the manually-operated foam maker with a permanent storage tank located on the ground floor of the turbine building was identified to be in the scope of license renewal and subject to an AMR. This foam system is to be used in the event of a 75,000 gallon outdoor FO storage tank fire, or diesel generator day tank fire, or diesel generator room fire. Further, the applicant states that LRA Table 3.3.2.8 includes line items for the tank andassociated piping and valves with fire protection foam as the internal environment. The applicant also states that the fire hoses associated with this foam system are outside the scope of license renewal since they are periodically replaced (short-lived components) and managed by the existing fire protection program. Therefore, the staff concludes that the turbine building foam systems and the associated components are correctly included in the scope of license renewal and subject to an AMR. The staff's concern described in RAI 2.3.3.8-4 is resolved.In RAI 2.3.3.8-5, dated August 15, 2006, the staff stated that SE Section 4.5 discusses floordrains provided in all plant areas protected with fixed water fire suppression. Are they in the scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and not subject to an AMR, the staff requested applicant provide justification for the exclusion.In its response, by letter dated September  20, 2006, the applicant stated:Water-filled components in the radioactive waste system (which includes thefloor drain system) that could affect safety-related equipment are in-scope and require an AMR in accordance with 10 CFR 54.4(a)(2) due to potential spatial interaction. These components are subject to an AMR and are addressed in LRA Table 3.3.2-13-32. Based on its review, the staff found the applicant's response to RAI 2.3.3.8-5 acceptable.Although the SE addresses these floor drains as associated with fire suppression, it is not included in LRA Table 3.3.2-8 "Fire Protection-Water System." Instead, it is included in LRA Table 3.3.2-13-32, "Radwaste Liquid & Solid (RDW) Nonsafety-Related Components Affecting Safety-Related Systems," which is in the scope for license renewal and subject to an AMR.
Because the applicant has committed to interpret these floor drains as included in the 2-84radioactive waste system, which is in the scope for license renewal and subject to an AMR, thestaff is adequately assured that the floor drains used for fire suppression will be considered appropriately during plant aging management activities. Therefore, the staff's concern described in RAI 2.3.3.8-5 is resolved.In RAI 2.3.3.8-6, dated August 15, 2006, the staff stated that the supplement to SE Section 3.3,dated February 20, 1980, discusses the fire protection features for the primary containment (e.g., fixed suppression systems, standpipe and hose stations, and oil collection system). The staff requested that the applicant determine whether fire protection systems and features for primary containment should be included as systems and components in-scope for license renewal and subject to an AMR. If not, the staff requested applicant explain the basis.In its response, by letter dated September  20, 2006, the applicant stated:Section 3.3 of the SE supplement dated February 20, 1980, discusses potentialfire protection features for the primary containment in the event the containment is not inerted. As noted in LRA Section 3.3.2.2.7, VYNPS is a BWR with an inert containment atmosphere. Therefore, the primary containment does not have a fixed suppression system or a reactor recirculation pump oil collection system.As shown on LRA drawing LRA-G-191163-SH-01-0, "Fire Protection System Inner Loop," hosestations in the reactor building that may be used for fire suppression in primary containment during non-inerted outage periods are in-scope and subject to an AMR.Based on its review, the staff found the applicant's response to RAI 2.3.3.8-6 acceptablebecause VYNPS is a BWR with an inert containment atmosphere and the primary containment does not have a fixed suppression system or a reactor recirculation pump oil collection system.
Further, the applicant states that during non-inerted outage periods, hose stations in the reactor building, may be used for fire suppression in primary containment. Therefore, the staff concludes that the fire protection features for the primary containment (e.g., fixed suppression systems, standpipe and hose stations, and oil collection system) are correctly excluded from the scope of license renewal and are not subject to an AMR. During the refueling outage, hose stations in the reactor building may be used for fire suppression in the primary containment.
This system was identified to be in the scope of license renewal and subject to an AMR.
Therefore, the staff's concern described in RAI 2.3.3.8-6 is resolved.In RAI 2.3.3.8-7, dated August 15, 2006, the staff stated that the supplement to SE Section 3.3,dated October 24, 1980, discusses the deluge system used to protect the turbine building lay-down area. The staff requested that the applicant determine whether the turbine building lay-down deluge system and its components should be included as systems and components in-scope for license renewal and subject to an AMR. If not, the staff requested applicant explain the basis.
2-85In its response, by letter dated September  20, 2006, the applicant stated:The turbine building loading bay is the area referred to in the SE supplement asthe turbine building lay-down area. The sprinkler system for this area is in-scope and subject to an AMR as shown on LRA drawing LRA-G-191163-SH-01-0, "Fire Protection System Inner Loop" at coordinate G-9.Based on its review, the staff found the applicant's response to RAI 2.3.3.8-7 acceptablebecause the deluge system and its components were identified to be in the scope of license renewal and subject to an AMR. Therefore, the staff concludes that this turbine building lay-down area deluge system and its associated components are correctly included in the scope of license renewal and subject to an AMR. The staff's concern described in RAI 2.3.3.8-7 is resolved.In RAI 2.3.3.8-8, dated August 15, 2006, the staff stated that SE Section 4.3.1(e) discusses theautomatic sprinkler systems used for various areas including the outdoor transformer. The LRA does not list the sprinkler systems nor associated components to protect the outdoor transformer. The staff requested that the applicant verify whether the sprinkler system and associated components are in-scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and not subject to an AMR, the staff requested applicant provide justification for the exclusion.In its response, by letter dated September  20, 2006, the applicant stated:As described in LRA Section 2.3.3.8, the fire protection system is in the scope oflicense renewal in accordance with 10 CFR 54.4(a)(3) because it is credited in the Appendix R safe-shutdown analysis as required by 10 CFR 50.48.The main transformer and auxiliary transformer sprinkler fire protectionsubsystems do not mitigate fires in areas containing equipment important to safe operation of the plant, nor are they credited with achieving safe-shutdown in the event of a fire. These subsystems are only required to meet state, municipal, or insurance requirements. Therefore, these subsystems have no intended function and are not included in the AMR summarized in LRA Table 3.3.2-8.Since they are outdoors and away from safety-related equipment, the maintransformer and auxiliary transformer sprinkler subsystems cannot affect safety-related equipment by spatial interaction and therefore, have no intended function as required by 10 CFR 54.4(a)(2). Therefore, these subsystems are not included in the AMR summarized in LRA Table 3.3.2-13-15. Based on its review, the staff found the applicant's response to RAI 2.3.3.8-8 acceptable.Although the main transformer and auxiliary transformer sprinkler systems are addressed in the SE, these systems in question are not credited to meet the requirements of Appendix R for achieving safe-shutdown in the event of a fire. In addition, the staff reviewed commitments made by the applicant to satisfy Appendix A to BTP APCSB 9.5-1, which discussed that the main transformer and auxiliary transformer are either located at least 50 feet from the building 2-86containing safety-related equipment or the wall of the building is a 3-hour fire-rated wall.Therefore, the staff finds that the main transformer and auxiliary transformer cannot affect safety-related equipment by spatial interaction and the sprinkler systems for the main transformer and auxiliary transformer were correctly excluded from the scope of license renewal and not subject to an AMR. Therefore, the staff's concern described in RAI 2.3.3.8-8 is resolved.In RAI 2.3.3.8-9, dated August 15, 2006, the staff stated that SE Section 5.12.6 discusses theuse of a 3-hour rated fire protection coating to protect the structural steel supporting the wall and ceiling of diesel generator rooms. The LRA does not list 3-hour rated fire protection coating for structural steel. The staff requested that the applicant verify whether the fire protection coating for structural steel is in-scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If fire protection coating is excluded from the scope of license renewal and not subject to an AMR, the staff requested applicant provide justification for the exclusion.In its response, by letter dated September 20, 2006, the applicant stated:Subsequent to the January 17, 1978, NRC Safety Evaluation, VYNPS notifiedthe NRC (in letter WVY 78-85) that a protective coating with a "fire resistant rating of approximately 1-hour" would be utilized for the structural steel supporting the roof and ceiling. This is based on the conclusion that a fire in one diesel generator room will not result in structural damage that could result in fire spread to the other room. The fire retardant coatings are in-scope and subject to an AMR and are included in the line item "Fire proofing" in LRA Tables 2.4-6 and 3.5.2-6.Based on its review, the staff found the applicant's response to RAI 2.3.3.8-9 acceptable. TheSE addresses the use of a 3-hour rated fire retardant coating to protect the structural steel supporting the wall and ceiling of the diesel generator rooms. The staff has confirmed that the applicant correctly identified the actual fire resistance rating of the structural steel coating ( i.e.,
1 hour). The fire resistance rating of the structural steel coating was clarified and included in the LRA Tables 2.4-6 and 3.5.2-6 and the coating is within the scope of license renewal and subject to an AMR. Therefore, the staff's concern described in RAI 2.3.3.8-9 is resolved. In RAI 2.3.3.8-10, dated August 15, 2006, the staff stated that LRA Table 2.3.3-8 excludesseveral types of fire protection components that appear in the SE and its supplements and/or updated UFSAR, and which also appear in the LRA drawings colored in purple. These components are listed below.
* hose stations
* hose connections
* hose racks
* pipe fittings
* pipe supports
* couplings
* threaded connections
* flexible hoses 2-87
* restricting orifices
* interface flanges
* chamber housings
* heat-actuated devices
* gauge snubbers
* tank heaters
* thermowells
* water motor alarms
* fire hydrants (casing)
* sprinkler heads
* dikes (contain oil spill)
* flame retardant coating for cables
* fire barrier penetration seals
* fire barrier walls, ceilings, floors, and slabs
* fire doors
* fire rated enclosures
* fire retardant coating for structural steel supporting walls and ceilings For each, the staff requested applicant determine whether the component should be included inTable 2.3.3.8, and if not, justify the exclusion.In its response, by letter dated September 20, 2006, the applicant stated the following:
* hose stations - Since they support criterion (a)(3) equipment, hosestations are included in the structural AMR. They are included in the "Fire hose reels" line item in LRA Table 2.4-6.
* hose connections - Hose connections are included in the "Piping" lineitem in LRA Table 2.3.3-8.
* hose racks - Since they support criterion (a)(3) equipment, hose racksare included in the structural AMR. They are included in the "Fire hose reels" line item in LRA Table 2.4-6.
* pipe fittings - As stated in LRA Section 2.0, the term "piping" incomponent lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Pipe fittings are included in the "Piping" line item in LRA Table 2.3.3-8.
* pipe supports - Since they support criterion (a)(3) equipment, pipingsupports are included in the structural AMR. They are included in the "Component and piping supports" line item in LRA Table 2.4-6.
* couplings - As stated in LRA Section 2.0, the term "piping" in componentlists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Couplings are pipe fittings included in the "Piping" line item in LRA Table 2.3.3-8.
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* threaded connections - As stated in LRA Section 2.0, the term "piping" incomponent lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Threaded connections are pipe fittings included in the "Piping" line item in LRA Table 2.3.3-8.
* flexible hoses - Hoses are replaced on a specified periodicity andtherefore, are not subject to an AMR as required by 10 CFR 54.21(a)(1)(ii).
* restricting orifices - As stated in LRA Section 2.0, the term "piping" incomponent lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Restricting orifices are included in the "Piping" line item in LRA Table 2.3.3-8.
* interface flanges - As stated in LRA Section 2.0, the term "piping" incomponent lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Interface flanges are pipe fittings included in the "Piping" line item in LRA Table 2.3.3-8.
* chamber housings - As shown on LRA drawing LRA-G-191163-SH-01-0,the turbine building lube oil room sprinkler system includes a retard chamber, piping, and valves whose purpose is to prevent false alarms due to system pressure surges and to provide a flow path to the water gong alarm during system actuation. Since failure of these components downstream of valve DV-76-200D would not prevent fire suppression capability for the lube oil room sprinkler system, they are not subject to an AMR.
* heat-actuated devices - As stated in UFSAR Section 10.11.3, thepre-action fire protection subsystems for the hydrogen seal oil area and the turbine building condenser and heater bay area have heat-actuated devices to initiate opening of the deluge valves. Heat-actuated devices are active components; not subject to an AMR.
* gauge snubbers - Gauge snubbers are integral parts of tubing runs thatprotect instrumentation from pressure surges. Gauge snubbers in tubing runs to instruments are included in the "tubing" line item in LRA Table 2.3.3-8.
* tank heaters - Neither the SE and its supplements nor the UFSARdiscuss tank heaters. Tank heaters do not appear on the LRA drawings colored in purple. VYNPS does not have fire water storage tanks and the foam concentrate tanks do not have heaters. Therefore, the fire protection - water system does not have tank heaters.
* thermowells - As stated in LRA Section 2.0, the term "piping" incomponent lists may include pipe, pipe fittings (such as elbows and 2-89reducers), flow elements, orifices, and thermowells. Thermowells areincluded in the "Piping" line item in LRA Table 2.3.3-8.
* water motor alarms - This response assumes that reviewer means waterflow alarms which are provided in critical locations and annunciate in the control room to provide positive indication of fire water system operation.
Water flow alarms are active components; not subject to an AMR.
* fire hydrants (casing) - As described in response to RAI 2.3.3.8-1, theyard fire hydrants are not subject to an AMR. By letter dated December 4, 2006, the applicant stated that the yard fire hydrants are in-scope and subject to an AMR. The hydrants are identified as component type "valve body" in LRA Table 2.3.3-8. Results of the AMR are provided in LRA Table 3.3.2-8 for line items "valve body" with carbon steel as the material and raw water as the environment.
* sprinkler heads - Sprinkler heads are included in the "Flow nozzle" lineitem in LRA Table 2.3.3-8.
* dikes (contain oil spill) - Dikes are included in the structural AMR. Theyare included in the "Flood curb" line items in LRA Table 2.4-6.
* flame retardant coating for cables - As described in response toRAI 2.3.3.8-3, flame retardant (flamemastic) coatings are subject to an AMR and are included in the line item "Fire wrap" in LRA Table 2.4-6.
Flamemastic was inadvertently omitted from the list of materials for the line item "Fire wrap" in LRA Table 3.5.2-6.
* fire barrier penetration seals - Fire barrier penetration seals are includedin the structural AMR. They are included in the "Penetration sealant (fire, flood, radiation)" line item in Table 2.4-6.
* fire barrier walls, ceilings, floor, and slabs - Fire barrier walls, ceilings,floor, and slabs are included in the structural AMR. They are included in the concrete line items in Tables 2.4-2 through 2.4-4.
* fire doors - Fire doors are included in the structural AMR. They areincluded in the "Fire doors" line item in Table 2.4-6.
* fire rated enclosures - As stated in SE Section 5.17.1, the diesel day tankfor the fire pump is located in a separate 3-hour fire rated enclosure. This enclosure consists of concrete block walls in the intake structure and is included in the structural AMR. It is included in the "Masonry walls" line item in Table 2.4-3.
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* fire retardant coating for structural steel supporting wall and ceiling - Asdescribed in response to RAI 2.3.3.8-9, fire retardant (flamemastic) coatings are subject to an AMR and are included in the line item "Fire wrap" in LRA Table 2.4-6. Flamemastic was inadvertently omitted from the list of materials for the line item "Fire wrap" in LRA Table 3.5.2-6. Based on its review, the staff found the applicant's response to RAI 2.3.3.8-10 acceptable.Although the applicant states that they consider these components to be included in other line items, the descriptions of the line items in the LRA do not list all these components specifically.
The applicant properly identified the following components to be included in the other line items in the scope of license renewal and subject to an AMR: hose racks, pipe fittings, pipe supports, couplings, threaded connections, restricting orifices, interface flanges, gauge snubbers, thermowells, sprinkler heads, dikes, flame retardant coating for cables, fire barrier penetration seals, fire barrier walls, ceilings, floors, slabs, fire doors, fire rated enclosures, and fire retardant coating for structural steel supporting walls and ceilings. The staff is adequately assured that these components will be considered appropriately during the plant aging management activities. For each of the following components, the staff found that they were not included in the line item descriptions in the LRA: flexible hoses, chamber housings, heat-actuated devices, tank heaters, and water motor alarms. The staff recognizes the applicant's interpretation of these components as active or short-lived components will result in more vigorous oversight of the condition and performance of the components. Because the applicant has interpreted that these components are active, the staff concludes that the components were correctly excluded from the scope of license renewal and are not subject to an AMR. Therefore, the staff's concern described in RAI 2.3.3.8-10 is resolved.In RAI 2.3.3.8-11, dated August 15, 2006, the staff stated that LRA Table 2.3.3-8 listed flownozzles (flow control) as in-scope and subject to an AMR, but does not list spray nozzles (water). The staff requested applicant to explain why the water spray nozzles are not subject to an AMR.In its response, by letter dated September 20, 2006, the applicant stated:Water spray nozzles are in-scope and subject to an AMR. They are included in the line item "Flow nozzles" in LRA Table 2.3.3-8.Based on its review, the staff finds the applicant's response to RAI 2.3.3.8-11 acceptablebecause it adequately explains that the spray nozzles in question are within the scope of license renewal and subject to an AMR. Further, the applicant stated that the spray nozzles are represented in the LRA Table by the component type "Flow nozzles" in LRA Table 2.3.3-8."
Therefore, the staff's concern described in RAI 2.3.3.8-11 is resolved.2.3.3.8.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the fire protection-water system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-912.3.3.9  Fire Protection-Carbon Dioxide2.3.3.9.1  Summary of Technical Information in the Application LRA Section 2.3.3.9 describes the fire protection-CO 2 system. The purpose of the fireprotection system is to provide fire protection for the station through the use of water, CO 2, drychemicals, foam, detection and alarm systems, and rated fire barriers, doors, and dampers.
The cable vault and switchgear rooms are protected by fully automatic total flooding CO 2suppression systems initiated by ionization detectors. Bottles located in the west switchgear room also may provide a backup or second shot to the cable vault if desired. The diesel fire pump FO storage tank room is protected by a total flooding CO 2 suppression system initiatedby heat detectors. The automatic total flooding high-pressure CO 2 gas suppression systems forthe cable vault and diesel fire pump FO storage tank room store high-pressure CO 2 at ambienttemperatures in steel CO 2 tanks. Empty fixed piping systems convey CO 2 from the tanks toopen nozzles in the fire area. The cable vault CO 2 system (automatic total flooding system with CO 2 tanks in the cable vault) is cross-connected to the CO 2 tanks in the west switchgear roomfor back-up capability for cable vault fire protection. The east and west switchgear rooms are protected by automatic total flooding low-pressure CO 2 systems. Low-pressure CO 2 is stored atapproximately 0 F in an outside storage tank. Empty fixed piping systems convey CO 2 from thestorage tank to open nozzles in the fire area.The fire protection-CO 2 system performs functions that support fire protection.LRA Table 2.3.3-9 identifies the following fire protection-CO 2 system component types withinthe scope of license renewal and subject to an AMR:
* bolting
* coil
* filter housing
* heater housing
* nozzle
* orifice
* piping
* pump casing
* siren body
* strainer
* tank
* tubing
* valve bodyIn LRA Table 3.3.2-9, the applicant provides the results of the AMR.
The fire protection-CO 2 system component intended functions within the scope of licenserenewal include the following:
* flow control
* filtration
* pressure boundary 2-922.3.3.9.2  Staff EvaluationThe staff reviewed LRA Section 2.3.3.9 and UFSAR Section 10.11 using the evaluationmethodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).The staff also reviewed the approved fire protection SER, dated January 13, 1978, approvingthe VYNPS fire protection program and supplemental SERs listed in the VYNPS Operating License Condition g.3.F. This report is referenced directly in the VYNPS fire protection CLB and summarizes the fire protection program and commitments to requirements of 10 CFR 50.48 using BTP APCSB 9.5-1, ?Guidelines for Fire Protection for Nuclear Power Plants," May 1,1976, and Appendix A to BTP APCSB 9.5-1, August 23, 1976. The staff then reviewed those components that the applicant identified as being within the scope of license renewal to verify that the applicant did not omit any passive and long-lived components that should be subject to an AMR as required by 10 CFR 54.21(a)(1). The staff's review of LRA Section 2.3.3.9 identified areas requiring additional informationnecessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.3.9-1, dated August 15, 2006, the staff stated that SE Sections 3.1.5 and 4.3.2discuss a total flooding CO 2 system for the cable spreading area, battery room, and dieseldriven fire water pump tank room. The LRA does not list the CO 2 system for the cablespreading area, battery room, and diesel driven fire water pump tank room. The staff requested that the applicant verify whether the CO 2 system and its components are in-scope of licenserenewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and not subject an AMR, the staff requested applicant to provide justification for the exclusion.In its response, by letter dated September 20, 2006, the applicant stated:As described in LRA Section 2.3.3.9, the cable vault and switchgear rooms areprotected by fully automatic total flooding CO 2 suppression systems initiated byionization detectors. Bottles located in the west switchgear room may also provide a backup or second shot to the cable vault if desired. The diesel fire pump FO storage tank room is protected by a total flooding CO 2 suppressionsystem initiated by heat detectors.As further described in LRA Section 2.3.3.9, the fire protection-CO 2 system iswithin the scope of license renewal and has the following intended function as required by 10 CFR 54.4(a)(3).
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* Provide the capability to extinguish fires in vital areas of the plant(10 CFR 50.48).The cable vault is the area referred to in the SE as the cable spreading area andbattery room. Therefore, the CO 2 systems for the cable spreading area, batteryroom, and diesel driven fire water pump tank room are in-scope and subject to an AMR.Based on its review, the staff found the applicant's response to RAI 2.3.3.9-1 acceptablebecause the total flooding CO 2 systems for the cable spreading area, battery room, and dieseldriven fire water pump tank room were identified to be in the scope of license renewal and subject to an AMR. Further, the applicant clarified that the cable vault is the area referred to in the SE as the cable spreading area and battery room. Therefore, the staff concludes that the total flooding CO 2 systems for the cable spreading area, battery room, and diesel driven firewater pump tank room and the associated components are correctly included in the scope of license renewal and subject to an AMR. The staff's concern described in RAI 2.3.3.9-1 is resolved.
 
In RAI 2.3.3.9-2, dated August 15, 2006, the staff stated that LRA Table 2.3.3-9 excludes several types of CO 2 fire suppression system components that appear in the SE and itssupplements and/or UFSAR, and which also appear in the LRA drawings colored in purple.
These components are listed below.
* strainer housings
* pipe fittings
* pipe supports
* couplings
* odorizer
* threaded connections
* flexible hose
* latch door pull box
* pneumatic actuators
* CO 2 bottles (CO 2 storage cylinders)For each, determine whether the component should be included in Table 2.3.3.9, and if not, thestaff requested applicant justify the exclusion.In its response, by letter dated September 20, 2006, the applicant stated:
* strainer housings - The CO 2 fire protection storage tank (TK-115-1)recirculation heater pump suction strainer (S-76-3) shown on LRA drawing LRA-G-191163-SH-03-0 has both filtration and pressure boundary functions. The strainer and its housing are both included in the "Strainer" line item in LRA Table 2.3.3-9.
* pipe fittings - As stated in LRA Section 2.0, the term "piping" in component lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Pipe fittings are 2-94included in the "Piping" line item in LRA Table 2.3.3-9.
* pipe supports - Since they support criterion (a)(3) equipment, pipingsupports are included in the structural AMR. They are included in the "Component and piping supports" line item in LRA Table 2.4-6.
* couplings - As stated in LRA Section 2.0, the term "piping" in component lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Couplings are pipe fittings included in the "Piping" line item in LRA Table 2.3.3-9.
* odorizer - Odorizer cylinders (OC-700, 701, 702, and 703) on switchgear room discharge lines are shown on LRA drawing LRA-G-191163-SH-03-0. The odorizer cylinders are included in the "Tank" line item in LRA Table 2.3.3-9.
* threaded connections - As stated in LRA Section 2.0, the term "piping" in component lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Threaded connections are pipe fittings included in the "Piping" line item in LRA Table 2.3.3-9.
* flexible hose - Hoses are replaced on a specified schedule and therefore, are not subject to an AMR as required by 10 CFR 54.21(a)(1)(ii).
* latch door pull box - This response assumes the reviewer means emergency manual release stations to initiate CO 2 flow. Manual releasestations are active components; not subject to an AMR.
* pneumatic actuators - Pneumatic actuators (discharge delay timers) on deluge valves for the switchgear rooms are shown on LRA drawing LRA-G-191163-SH-03-0. Since the actuator subcomponents have a pressure boundary function, they are included in the line items for "Tank,"
"Valve body," and "Tubing" in Table 2.3.3-9.
* CO 2 bottles (CO 2 storage cylinders) - The CO 2 bottles, or storagecylinders, are included in the line item "Tank" in Table 2.3.3-9.Based on its review, the staff found the applicant's response to RAI 2.3.3.9-2 acceptable.Although the applicant states that they consider these components to be included in other line items, the LRA descriptions of the line items do not specifically list all these components. The applicant identified the following components to be included in other line items in the scope of license renewal and subject to an AMR: strainer housings, pipe fittings, pipe supports, couplings, odorizer, threaded connections, pneumatic actuators, and CO 2 bottles. The staff isassured that the listed components will be considered appropriately during plant aging management activities. The staff found that the following components were not included in the line item descriptions in the LRA: flexible hoses and latch door pull box (emergency manual release stations to initiate CO 2 flow). The staff recognizes the applicant's interpretation of thesecomponents as active or short-lived components, which will result in more vigorous oversight of 2-95the condition and performance of the components. Because the applicant has interpreted thesecomponents are active, the staff concludes that the components were correctly excluded from the scope of license renewal and are not subject to an AMR. Therefore, the staff's concern described in RAI 2.3.3.9-2 is resolved.In RAI 2.3.3.9-3, dated August 15, 2006, the staff stated that LRA Table 2.3.3-9 listed nozzleswith an intended function of flow control as in-scope and subject to an AMR. Nozzles with intended functions of total flood, vent, and S nozzles are not listed. The staff requested that the applicant explain why these nozzles are not subject to an AMR.In its response, by letter dated September 20, 2006, the applicant stated:The total flood nozzles in the CO 2 system are subject to an AMR, as indicated ondrawings LRA-G-191163-SH-03-0 and LRA-G-191163-SH-04-0. They are included in the "Nozzle" line item in Table 2.3.3-9. As shown on the LRA drawings the CO 2 system does not have vent or S nozzles. Based on its review, the staff finds the applicant's response to RAI 2.3.3.9-3 acceptablebecause it adequately explains that the flood nozzles in question are within the scope of license renewal and subject to an AMR. Further, the applicant stated that the flood nozzles are represented in the LRA Table 2.3.3-9 by the component type "Nozzles," and the CO 2 systemdoes not have vent or S nozzles. Therefore, the staff's concern described in RAI 2.3.3.9-3 is resolved.2.3.3.9.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of License renewal or subject to an AMR. The staff finds no such omissions.
On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the fire protection-CO 2 system components within the scopeof license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.10  Heating, Ventilation, and Air Conditioning2.3.3.10.1  Summary of Technical Information in the Application LRA Section 2.3.3.10 describes the heating, ventilation, and air conditioning (HVAC) and thehouse HB systems. The purpose of the HVAC system is to maintain the general area environment for personnel and equipment. It consists of several ventilation systems serving ten different areas of the plant: (1) primary containment ventilation normally operates to maintain drywell ambient temperature within acceptable ranges, (2) reactor building ventilation provides filtration and controls temperature, humidity, and migration of air from clean areas to areas of higher contamination, including exhaust to the plant stack. It also purges the drywell, (3) turbine building ventilation provides filtration and controls temperature, humidity, and migration of air from clean areas to areas of higher contamination. It exhausts building air to the plant stack (normal intake and exhaust function) in a monitored release path, (4) DG room ventilation supports operation of the EDGs, (5) control building ventilation maintains the environment in the 2-96main control room, (6) service building ventilation provides filtration, controls temperature andhumidity, and exhausts potential contaminants to the plant stack. It maintains the hydrogen concentration well below 2 percent by volume in the HVAC equipment room (hydrogen is potentially generated from the AS-1 batteries), (7) radwaste building ventilation provides filtration (including filtration of exhaust sent to the plant stack) and controls temperature, humidity, and migration of air from clean areas to areas of higher contamination, (8) augmented off-gas building ventilation provides filtration (including filtration of exhaust sent to the plant stack) and temperature and humidity control, (9) intake structure ventilation maintains an environment suitable for operating personnel and equipment, including the diesel-driven fire pump, and (10) JDD building ventilation cools the JDD, which provides emergency lighting credited in the Appendix R safe shutdown capability assessment. The purpose of the HB system is to provide a source of steam for space heating and process requirements during all phases of station operation and heats the control room during normal operation. The system has two 50-percent boilers, various heaters, steam traps, valves, and piping.The HVAC and HB systems have safety-related components relied upon to remain functionalduring and following DBEs. The failure of nonsafety-related systems SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the systems perform functions that support fire protection.LRA Tables 2.3.3-10, 2.3.3-13-18, and 2.3.3-13-21 identify the following HVAC and HB systemcomponent types within the scope of license renewal and subject to an AMR:
* bolting
* compressor housing
* damper housing
* duct
* duct flexible connection
* expansion joint
* fan housing
* filter housing
* heat exchanger (fins)
* heat exchanger (housing)
* heat exchanger (shell)
* heater housing
* humidifier housing
* louver housing
* piping
* pump casing
* sight glass
* steam trap
* strainer
* strainer housing
* tank
* tubing
* valve body 2-97The HVAC and HB system component intended functions within the scope of license renewalinclude the following:
* filtration
* heat transfer
* pressure boundary2.3.3.10.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.10 and UFSAR Sections 5.2.3.7, 5.3.5, 10.7.6, and 10.12using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LRSection 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.10.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the HVAC and HB system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.11  Primary Containment Atmosphere Control / Containment Atmosphere Dilution2.3.3.11.1  Summary of Technical Information in the Application LRA Section 2.3.3.11 describes the PCAC system, the containment atmosphere dilution (CAD)system, and the post-accident sampling system (PASS). The purpose of the PCAC system is to ensure that the containment atmosphere is inerted with N 2 during station power operation. ThePCAC system establishes and maintains the required differential pressure between the drywell and torus. System instrumentation monitors key drywell and torus parameters, including temperature, pressure, moisture, drywell to torus differential pressure, and torus water level.
The CAD system limits the concentration of oxygen in the primary containment so ignition of hydrogen and oxygen from a metal-water reaction following a LOCA will not occur. The PASS is included in this evaluation. The purpose of PASS is to provide representative samples of reactor coolant indicative of the extent and development of core damage.The PCAC system, CAD system, and PASS have safety-related components relied upon toremain functional during and following DBEs. The failure of nonsafety-related SSCs in the system potentially could prevent the satisfactory accomplishment of a safety-related function.
2-98LRA Tables 2.3.3-11, 2.3.3-13-3, 2.3.3-13-27, and 2.3.3-13-28 identify the following PCACsystem, CAD system, and PASS component types within the scope of license renewal and subject to an AMR:
* bolting
* diaphragm
* dryer
* duct
* filter housing
* heat exchanger
* orifice
* piping
* pump casing
* tank
* trap
* tubing
* valve bodyThe component intended functions within the scope of license renewal include the following:
* flow control
* heat transfer
* pressure boundary2.3.3.11.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.11 and UFSAR Sections 5.2.3.6, 5.2.6, 5.2.7, and 10.20using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LRSection 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.11 identified areas in which additional information wasnecessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.3.11-1 dated August 16, 2006, the staff stated that license renewal drawingLRA-VY-E-75-002-0, at location K-13, penetration X209D to the H 2 O 2 analyzers, shows asection of pipe to be within the scope of license renewal. However, this same section of pipe on drawing LRA-G-191165-0, at location E-16 from penetration X209D through the continuation to drawing LRA-VY-E-75-002-0, is not shown to be within the scope of license renewal. The staff requested that the applicant confirm that this section of pipe is within the scope of license renewal, or if not, justify its exclusion.
2-99In its response dated September 20, 2006, the applicant stated that the section of pipe shownon license renewal drawing LRA-VY-E-75-002-0, at location K-13 at penetration X209D to the
 
H 2 O 2 analyzers and on drawing LRA-G-191165-0, at location E-16 from penetration X209Dthrough the continuation to drawing LRA-VY-E-75-002-0 is within the scope of license renewal and subject to an AMR. Dashed lines (or phantom lines) on the drawings indicate that the actual line is shown on its primary system drawing. Phantom lines are not highlighted on the license renewal drawings. Based on its review, the staff found the applicant's response to RAI 2.3.3.11-1 acceptablebecause the applicant confirmed that containment atmosphere dilution system piping1"-VG-122-D1 connecting the H 2 O 2 analyzers to the torus through penetration X-209D is withinthe scope of license renewal and subject to an AMR. Therefore, the staff concern described inRAI 2.3.3.11-1 is resolved.In RAI 2.3.3.11-2 dated August 16, 2006, the staff stated that license renewal drawingLRA-VY-E-75-002-0, at location J-9 shows a pipe section, including valve NG-16 to pipe section 20-AC-13, within the scope of license renewal. However, this same section of pipe on drawing LRA-G-191175-SH-01-0, at location K-10 is not shown within the scope of license renewal. The staff requested that the applicant confirm that this section of pipe is within the scope of license renewal, or if not, to justify its exclusion.In its response dated September 20, 2006, the applicant stated that the section of pipe shownon license renewal drawing LRA-VY-E-75-002-0, at location J-9, including valve NG-16 to pipe section 20-AC-13 and on drawing LRA-G-191175-SH-01-0, at location K-10 is within the scope of license renewal and subject to an AMR. Dashed lines (or phantom lines) on the drawings indicate that the actual line is shown on its primary system drawing. Phantom lines are not highlighted on the license renewal drawings. Based on its review, the staff found the applicant response to RAI 2.3.3.11-2 acceptablebecause the applicant confirmed that containment atmosphere dilution system piping fromprimary containment and atmosphere control system piping 20"- AC-13 to valve NG-16 (1"NG-101A-EIN2) is within the scope of license renewal and subject to an AMR. Therefore, the staff concern described in RAI 2.3.3.11-2 is resolved.In RAI 2.3.3.11-3 dated August 16, 2006, the staff stated that license renewal drawingLRA-VY-E-75-002-0, at location G-7 provides a continuation from valve VG-77 to drawing LRA-G-191165-0 (at location B-17) that is within the scope of license renewal. However, the license renewal boundary could not be located on drawing LRA-G-191165-0 (at location B-17).
The staff requested that the applicant provide additional information for the continuation of this pipe section to the license renewal boundary and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a).In its response dated September 20, 2006, the applicant stated that license renewal drawingLRA-VY-E-75-002-0, at location G-17 provides a continuation from valve VG-77 to drawing LRA-G-191165-0 that is within the scope of license renewal. The drawing references location B-17 on drawing LRA-G-191165-0. The hydrogen/oxygen analyzers are shown at location H-14 on drawing LRA-G-191165-0. Therefore, the appropriate reference location for the continuation on drawing LRA-G-191165-0 is H-14. An engineering request was submitted to correct the 2-100discrepancy on license renewal drawing LRA-VY-E-75-002-0. The piping to VG-77 is connectedto 3/4" pipe VG-109-TI prior to valve VG-20. As shown on the drawings, all of the piping and components from the primary containment air space to the analyzers and from the analyzers to the torus are within the scope of license renewal and subject to an AMR.
Based on its review, the staff found the applicant response to RAI 2.3.3.11-3 acceptable because the applicant provided appropriate documentation to demonstrate that piping upstream of valve VG-77 was connected to primary containment sample system line 3/4" VG-109-T1, piping and components were correctly identified within the scope of license renewal, and license renewal boundaries were appropriately identified on the sampling system flow diagram, LRA-G-191165-0. Therefore, the staff concern described in RAI 2.3.3.11-3 is resolved.In RAI 2.3.3.11-4 dated August 16, 2006, the staff stated that license renewal drawingLRA-VY-E-75-002-0, at location J-18 shows a pipe section downstream of valve VG30A within the scope of license renewal. A drawing continuation to the license renewal boundary was not provided. The staff requested that the applicant provide additional information for the continuation of this pipe section to the license renewal boundary and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a).In its response dated September 20, 2006, the applicant stated that license renewal drawingLRA-VY-E-75-002-0 shows hydrogen/oxygen analyzer panel SII within a dotted rectangular box at locations H-17 through J-18. Above the box, at location G-18, VG-29A is shown going to hydrogen/oxygen analyzer panel SI, which is not shown but is the same as the SII panel. Valve VG-30A, below the box at location J-18, is coming back from the SI panel. As shown on the drawing, all of the piping and components from the analyzer panels to the torus are within the scope of license renewal and subject to an AMR. Based on its review, the staff found the applicant response to RAI 2.3.3.11-4 acceptablebecause the applicant adequately identified the piping and components in the H 2 O 2 analyzerSAH-VG-5A SI panel which are within the scope of license renewal and subject to an AMR.These components were identified as those corresponding to components identified in panel SIIon drawing LRA-VY-E-75-002-0. Therefore, the staff concern described in RAI 2.3.3.11-4 isresolved.In RAI 2.3.3.11-5 dated August 16, 2006, the staff stated that license renewal drawingLRA-VY-191165-0, at location I-15 provides a continuation of a pipe section from the H 2 0 2analyzers to drawing LRA-VY-E-75-002-0 that is within the scope of license renewal. However, the license renewal boundary could not be located on drawing LRA-VY-E-75-002-0. The staff requested that the applicant provide additional information for the continuation of this pipe section to the license renewal boundary and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a).In its response dated September 20, 2006, the applicant stated that an engineering request was submitted to correct the license renewal drawing discrepancies. Also, as shown on the drawings, all of the piping and components from the primary containment air space to the analyzers and from the analyzers to the torus are within the scope of license renewal and subject to an AMR.
2-101Based on its review, the staff found the applicant response to RAI 2.3.3.11-5 acceptablebecause the applicant confirmed that sample system piping located on drawing LRA-G-191165-0, at location I-15 and H-14, is continued on drawing LRA-VY-E-75-002-0.
Additionally, the applicant demonstrated these components and all of the piping and components from the primary containment air space to the analyzers and from the analyzers to the torus are within the scope of license renewal and subject to an AMR. Therefore, the staff concern described in RAI 2.3.3.11-5 is resolved.In RAI 2.3.3.11-6 dated August 16, 2006, the staff stated that license renewal drawingLRA-VY-191165-0, at location C-12 provides continuations to drawing LRA-G-191267 (at locations H-12 and H-5) for two pipe lines from the post-accident sampling panel that are within the scope of license renewal. The license renewal boundary could not be located on LRA-G-191267-SH-01-0. The staff requested that the applicant provide additional information for the continuation of these pipe sections to the license renewal boundary and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a).In its response dated September 20, 2006, the applicant confirmed that the two pipe lines fromthe post-accident sampling panel shown on license renewal drawing LRA-VY-191165-0, at location C-12 are continued on drawing LRA-G-191267-SH-01-0 (at location H-12 and H-5).
The lines are depicted as "TYPICAL FOR FT63A" and "TYPICAL FOR FT63C" with reference to FT63B and FT63D piping which are identified within dashed rectangles on drawing LRA-G-191267-SH-01-0 at the specified locations. The table on drawing LRA-G-191267-SH-02-0, at location A-16, notes the instrument root valves associated with each jet pump. Drawing LRA-G-191267-SH-01-0 identifies the piping and components from the jet pump to the instruments as being within the scope of license renewal and subject to an AMR as part of the RCS pressure boundary described in LRA Section 2.3.1.3. Drawing LRA-G-191165-0 shows piping continuing from jet pump instrument root valve V-20B (typical) to PASS valve 102 and 101 and from root valve V-20D (typical) to PASS valve 104 and 103.
The applicant confirmed that components in the sample line are within the scope of license renewal and subject to an AMR as part of the post-accident sampling system as described in LRA Section 2.3.3.11. Therefore, in accordance with 10 CFR 54.4(a)(1), the entire reactor coolant pressure boundary out to the second isolation valve on the PASS sample lines is within the scope of license renewal and subject to an AMR.Based on its review, the staff found the applicant response to RAI 2.3.3.11-6 acceptablebecause the applicant submitted appropriate documentation acknowledging that all piping and components associated with primary containment atmosphere control and containment atmosphere dilution are within the scope of license renewal and subject to an AMR including all the reactor coolant pressure boundary up to and including the second post-accident sampling system (PASS) isolation valves. Therefore, the staff concern described in RAI 2.3.3.11-6 is resolved.
2-1022.3.3.11.3  ConclusionThe staff reviewed the LRA accompanying license renewal drawings, and RAI responses todetermine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the PCAC system, CAD system, and PASS components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.12  John Deere Diesel2.3.3.12.1  Summary of Technical Information in the Application LRA Section 2.3.3.12 describes the JDD as a nonsafety-related skid-mounted engine poweringa generator that supplies back-up electric power to plant lighting. It is located in a separate structure, the JDD building. The diesel is started electrically with batteries and does not require cooling water from other plant systems. Its license renewal purpose is to provide power to lighting panels credited as emergency lighting in the Appendix R safe shutdown capability analysis.The JDD performs functions that support fire protection.
LRA Table 2.3.3-12 identifies the following JDD component types within the scope of licenserenewal and subject to an AMR:
* bolting
* expansion joint
* filter housing
* heat exchanger (radiator)
* heat exchanger (shell)
* heat exchanger (tubes)
* heater housing
* piping
* pump casing
* silencer
* tubing
* turbochargerThe JDD component intended functions within the scope of license renewal include thefollowing:
* heat transfer
* pressure boundary2.3.3.12.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.12 using the Tier-2 evaluation methodology described inSER Section 2.3 and the guidance in SRP-LR Section 2.3.
2-103In conducting its review, the staff evaluated the system functions described in the LRA to verifythat the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.12 identified areas in which information provided in theLRA needed to be confirmed by the NRC Regional Inspection Team to complete the review of the applicant's scoping and screening results.Inspection Item 2.3.3.12-1LRA Section 2.3.3.12 indicts that the John Deere Diesel is installed in compliance with10 CFR 50, Appendix R, requirements. However, due to a lack of available drawings and/or detailed description of the diesel equipment listed in LRA Table 2.3.3-12, it is difficult to determine if any AMR category components may have been omitted from the table. It is recommended that the JDD be inspected to assure all AMR category components are included in the list of LRA Table 2.3.3-12. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a) (3).In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRCLicense Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated that the John Deere diesel system components are listed in LRA Table 2.3.3-12 and the supporting fuel oil day tank, fiberglass underground storage tank, and supply lines are listed in LRA Table 2.3.3-6, "Fuel Oil System." Based on its review, the staff found the above response acceptable because the NRC RegionalInspection Team verified that all components subject to an AMR are included in LRA Table 2.3.3-12 and LRA Table 2.3.3-6 and confirmed that no other portions of the John Deere diesel system should have been included within scope based on 10 CFR 54.4(a)(3). Therefore, the staff concern described in Inspection Item 2.3.3.12-1 is resolved.2.3.3.12.3  Conclusion The staff reviewed the LRA and Inspection Item response to determine whether the applicantfailed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the JDD components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1042.3.3.13  Miscellaneous Systems In-scope as required by 10 CFR 54.4(a)(2)2.3.3.13.1  Summary of Technical Information in the Application LRA Section 2.3.3.13 describes the miscellaneous systems within the scope of license renewalrequirements of 10 CFR 54.4(a)(2). Such systems interact with safety-related systems in one of two ways: (1) a functional failure where the failure of a nonsafety-related SSC to perform its function impacts a safety function or (2) a physical failure where a safety function is impacted by the loss of structural or mechanical integrity of an SSC in physical proximity to a safety-related component.LRA Section 2.3.3.13.1 states that functional failures of nonsafety-related SSCs which couldimpact a safety function were identified only for systems with components supporting the main condenser and MSIV leakage pathway. Two of these systems are the augmented off-gas (AOG) and sampling systems, which are not described elsewhere in the LRA. Descriptions of these systems follow.2.3.3.13A Augmented Off-gas2.3.3.13A.1  Summary of Technical Information in the Application The AOG system collects, processes, and discharges radioactive gaseous wastes to theatmosphere through the plant stack during normal operation. The system reduces the released quantities of gaseous and particulate radioactive material from the site to levels as low as practical during normal operation. The AOG system has subsystems that dispose of gases from the main condenser air ejectors, the start-up vacuum pump, and the gland seal condenser. The various subsystems are monitored continuously for radiation.The failure of nonsafety-related SSCs in the AOG system could prevent the satisfactoryaccomplishment of a safety-related function.LRA Table 2.3.3.13-1 identifies the following AOG system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* filter housing
* piping
* stream trap
* tank
* tubing
* valve bodyThe AOG system component intended function within the scope of license renewal is to providea pressure boundary.
2-1052.3.3.13A.2  Staff EvaluationThe staff reviewed LRA Section 2.3.3.13.1 and UFSAR Section 9.4 using the Tier-2 evaluationmethodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.13.1 identified areas in which information provided inthe LRA needed to be confirmed by the NRC Regional Inspection Team to complete the review of the applicant's scoping and screening results.Inspection Item 2.3.3.13a-1The LRA states that the AOG system is within the scope of license renewal based onrequirements of 10 CFR 54.4(a)(2) because of the potential for physical interaction with safety-related components described in LRA Table 2.3.3.13-A. The determination of whether a component meets the requirements of 10 CFR 54.4(a)(2) for physical interactions is based on where it is located in a building and its proximity to safety-related equipment or where a structural/seismic boundary exists. This information is not provided on license renewal drawings nor was a detailed description provided in the LRA. Consequently, any omission of AOG components subject to an AMR cannot be determined. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components meet the requirements of 10 CFR 54.4(a)(2) and all the components subject to an AMR are included in LRA Table 2.3.3-13-1.In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRCLicense Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team noted LRA Table 2.3.3.13-B states that the portion of the AOG system associated with the plant stack loop seal is subject to an AMR based on 10 CFR 54.4(a)(2) for physical interactions. Since the boundaries for the portion of the system as described in LRA Table 2.3.3.13-B were not well defined, in its letter dated July 30, 2007, the applicant amended the table to read "portion of the system inside the plant stack." The inspector walked down the remainder of the system and confirmed that no other portions of the system should have been included based on 10 CFR 54.4(a)(2).Based on its review, the staff found the above response acceptable because the applicantamended LRA Table 2.3.3.13-B as appropriate and the NRC regional inspector walked down the remainder of the AOG system outside the plant stack and confirmed that no other portions of the system should have been included within scope based on 10 CFR 54.4(a)(2). Therefore, the staff concern described in Inspection Item 2.3.3.13a-1 is resolved.
2-1062.3.3.13A.3  ConclusionThe staff reviewed the LRA, accompanying license renewal drawings, and inspection itemresponse to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the AOG system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13B Sampling2.3.3.13B.1  Summary of Technical Information in the Application The sampling system provides means for sampling and testing various process fluids in thestation in centralized locations. Fluids and gases are sampled continuously or periodically from equipment or systems reflecting station performance.The failure of nonsafety-related SSCs in the sampling system could prevent the satisfactoryaccomplishment of a safety-related function.LRA Table 2.3.3.13-41 identifies the following sampling system component types within thescope of license renewal and subject to an AMR:
* bolting
* piping
* stainer housing
* tubing
* valve bodyThe sampling system component intended function within the scope of license renewal is toprovide a pressure boundary.2.3.3.13B.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.1 and UFSAR Section 10.17 using the Tier-2evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LRSection 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).
2-1072.3.3.13B.3  ConclusionThe staff reviewed the LRA and accompanying license renewal drawings to determine whetherthe applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the sampling system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).Besides the augmented off-gas and sampling systems, other systems with componentssupporting the main condenser and MSIV leakage pathway where functional failures of nonsafety-related SSCs could impact a safety function are addressed in LRA Section 2.3.4.LRA Table 2.3.3.13-A shows systems within the scope of license renewal with potential forphysical interactions with safety-related components based on the criterion of 10 CFR 54.4(a)(2). Of these systems, the applicant stated that the following are not described elsewhere in the LRA:
* circulating water
* condensate demineralizer
* demineralized water
* equipment retired in place
* feedwater
* MG lube oil
* neutron monitoring
* potable water
* radwaste, liquid and solid
* reactor water clean-up
* RWCU filter demineralizer
* stator coolingA description of each system above follows.2.3.3.13C Condensate Demineralizer2.3.3.13C.1  Summary of Technical Information in the Application The condensate demineralizer (CD) system maintains the required purity of feedwater suppliedto the reactor. The system minimizes corrosion product in the nuclear system so it does not affect fuel performance, nuclear system component accessibility, or the capacity required of the RWCU system. The CD system protects the nuclear system against the entry of foreign material due to condenser leaks. The system uses finely ground, mixed ion-exchange resins deposited upon the tubular elements of pressure precoat type filters (the filter-demineralizer units). The CD consist of five filter-demineralizer units (including an installed spare) operating in parallel. All are normally operated but sized so four units can support operation.The failure of nonsafety-related SSCs in the CD system potentially could prevent thesatisfactory accomplishment of a safety-related function.
2-108LRA Table 2.3.3-13-4 identifies the following CD system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* filter housing
* piping
* pump casing
* strainer housing
* tank
* tubing
* valve bodyThe CD system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13C.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.7 using the evaluationmethodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13C.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the CD system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13D RWCU Filter Demineralizer2.3.3.13D.1  Summary of Technical Information in the Application The RWCU filter demineralizer (CUFD) system filters and cleans reactor water. The CUFD isthe filter-demineralizer portion of the RWCU system and consists of the filter/demineralizer tanks, piping, and valves.The failure of nonsafety-related SSCs in the CUFD system potentially could prevent thesatisfactory accomplishment of a safety-related function.
2-109LRA Table 2.3.3-13-8 identifies the following CUFD system component types within the scopeof license renewal and subject to an AMR:
* bolting
* filter housing
* orifice
* piping
* pump casing
* sight glass
* strainer housing
* tank
* tubing
* valve bodyThe CUFD system component intended function within the scope of license renewal is toprovide pressure boundary.2.3.3.13D.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 4.9 using the Tier-1 evaluationmethodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13D.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the CUFD system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13E Circulating Water2.3.3.13E.1  Summary of Technical Information in the Application The circulating water (CW) system is a heat sink for steam condensation for the maincondensers. Heat removal in the condensers is accomplished by a continuous supply of cooling water pumped from and returned to the Connecticut River or by recirculation flow pumped through cooling towers by three vertical circulating water pumps in the intake structure. Trash 2-110racks and traveling water screens protect the circulating water pumps from debris. During coldweather, recirculation of water from the discharge structure to the intake structure prevents icing at the screens and intakes. Two cooling towers have the capacity to remove the total heat load from the circulating water. Three vertical circulating water booster pumps provide the necessary head for cooling tower operation and the recirculation mode.The CW system has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related SSCs in the CW system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-9 identifies the following CW system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* expansion joint
* piping
* pump casing
* tank
* tubing
* valve bodyThe CW system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13E.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2, and UFSAR Sections 10.8, 11.6, and 11.9 using theTier-2 evaluation methodology described in SER Section 2.3. and the guidance described inSRP-LR Section 2.3.In conducting its review, the evaluated the system functions described in the LRA and UFSARto verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.13 identified areas in which information provided in theLRA needed to be confirmed by the NRC Regional Inspection Team to complete the review of the applicant's scoping and screening results.Inspection Item 2.3.3.13e-1The LRA states that the circulating water system is within the scope of license renewal basedon the potential for physical interaction with safety-related components as required by 10 CFR 54.4(a)(2) and described in LRA Table 2.3.3.13-A. The applicant did not provide drawings highlighting in-scope components required by 10 CFR 54.4(a)(2), stating that the drawings would not provide significant additional information because they do not indicate 2-111proximity of components to safety-related equipment and do not identify structural/seismicboundaries. Without license renewal drawings and/or detailed description of the circulating water system, the omission of components subject to an AMR cannot be determined (see LRA Table 2.3.3-13-9). The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(2) and all the components subject to an AMR are included in LRA Table 2.3.3-13-9.In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRCLicense Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope. Further, applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 states that there are no nonsafety-related systems for which the applicant has not identified the nonsafety-related portions of systems which are attached to safety-related systems and required to be in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). However, as a result of discussions with the staff during the Region I inspection (February 2007), the applicant determined that some safety-related SSCs in the VY turbine building required consideration for potential spatial impacts from nonsafety-related SSCs in accordance with 10 CFR 54.4(a)(2). Therefore, an expanded review for SSCs in the turbine building determined that additional components required an AMR. Those additional component types were added to LRA Table 2.3.3-13-9, as addressed in the applicant's letters to the staff dated July 30, 2007 and August 16, 2007. Based on its review, the staff found the above response acceptable because the applicantstated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope in accordance with 10 CFR 54.4(a)(2) but that there were spatial impact concerns from nonsafety-related SSCs in the turbine building. The additional component types have been added to LRA Table 2.3.3-13-9. Therefore, the staff concern regarding components of the CW system described in Inspection Item 2.3.3.13e-1 is resolved.2.3.3.13E.3  Conclusion The staff reviewed the LRA and the inspection item response to determine whether theapplicant failed to identify any SSCs within the scope of license renewal or subject to an AMR.
The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the CW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13F Demineralized Water2.3.3.13F.1  Summary of Technical Information in the Application The demineralized water (DW) system provides treated makeup water for such plantcomponents as the condensate storage tank, spent fuel pool, RBCCW, and turbine building 2-112closed cooling water systems. This supply function is not a safety function. The DW systemconsists of the demineralized water transfer system including the demineralized water storage tank, demineralized water transfer pumps, piping, and valves, but not including the condensate storage tank or CST system components.The failure of nonsafety-related SSCs in the DW system potentially could prevent thesatisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-12 identifies the following DW system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* orifice
* piping
* pump casing
* tank
* tubing
* valve bodyThe DW system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13F.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 10.13.3 using the Tier-2evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LRSection 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13F.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the DW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1132.3.3.13G Feedwater2.3.3.13G.1  Summary of Technical Information in the Application The feedwater (FW) system provides demineralized water from the condensate system to thereactor vessel at a rate sufficient to maintain adequate reactor vessel water level. The FW system consists of three reactor feedwater pumps, four high-pressure feedwater heaters (two per train), valves, and piping.The failure of nonsafety-related SSCs in the FW system potentially could prevent thesatisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-13 identifies the following FW system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* heat exchanger (shell)
* orifice
* piping
* pump casing
* strainer housing
* tubing
* valve bodyThe FW system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13G.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.8 using the Tier-2 evaluationmethodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13G.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the FW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1142.3.3.13H MG Lube Oil2.3.3.13H.1  Summary of Technical Information in the Application The MGLO system lubricates the reactor recirculation pump motor generator set during itsoperation. The MGLO system has lube oil pumps, heat exchangers, piping, and valves.The failure of nonsafety-related SSCs in the MGLO system potentially could prevent thesatisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-23 identifies the following MGLO system component types within the scopeof license renewal and subject to an AMR:
* bolting
* heat exchanger (shell)
* piping
* pump casing
* tubing
* valve bodyThe MGLO system component intended function within the scope of license renewal is toprovide pressure boundary.2.3.3.13H.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 7.9.4.4.1 using the evaluationmethodology described in SER Section 2.3. and guidance described in SRP-LR Section 2.3.In conducting its review, the evaluated the system functions described in the LRA and UFSARto verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13H.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the MGLO system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1152.3.3.13I Neutron Monitoring2.3.3.13I.1  Summary of Technical Information in the Application The neutron monitoring (NM) system indicates neutron flux, which can be correlated to thermalpower level, for the entire range of flux conditions in the core. The system consists of in-core neutron detectors and out-of-core electronic monitoring equipment. The source-range and intermediate-range monitors indicate flux levels during reactor startup and lower power operation. The local-power range and average-power range monitors assess local and overall flux conditions during power range operation. Rod block monitors prevent rod withdrawal when reactor power should not be increased at the current reactor coolant flow rate. The traversing in-core probe system calibrates individual neutron monitoring sensors. The safety function of the NM system is to detect conditions in the core that threaten the overall integrity of the fuel barrier by excessive power generation and to provide signals to the reactor protection system to limit the release of radioactive material from the fuel barrier.The NM system has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related SSCs in the NM system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-26 identifies the following NM system component types within the scope oflicense renewal and subject to an AMR:
* piping
* tubing
* valve bodyThe NM system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13I.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2, and UFSAR Sections 1.6.2.2, 1.6.4.1.3, and 7.5using the evaluation methodology described in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.The staff evaluated the system functions described in the LRA and UFSAR to verify that theapplicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).
2-1162.3.3.13I.3  ConclusionThe staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the NM system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13J Potable Water2.3.3.13J.1  Summary of Technical Information in the Application The potable water (PW) system supplies treated water suitable for drinking and for sanitarypurposes to lavatories, service sinks, combination emergency showers and eyewashes, kitchen sinks, bench sinks, showers, and wall hydrants.The failure of nonsafety-related SSCs in the PW system potentially could prevent thesatisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-29 identifies the following PW system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* filter housing
* piping
* strainer housing
* tank
* valve bodyThe PW system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13J.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 10.15 using the Tier-1evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LRSection 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).
2-1172.3.3.13J.3  ConclusionThe staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the PW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13K Radwaste, Liquid and Solid2.3.3.13K.1  Summary of Technical Information in the Application The purpose of the liquid radwaste (RDW) system is to collect potentially radioactive liquidwastes, treats them, and returns the processed radioactive liquid wastes to the station for reuse. The solid RDW system collects and processes radioactive solid wastes for temporary onsite storage and offsite shipment for permanent disposal. The RDW system monitors the drywell floor and equipment drain sump pump-out rate for reactor coolant leak detection. The liquid portion of the RDW system consists of floor and equipment drains for handling tanks, piping, pumps, process equipment, instrumentation, and auxiliaries necessary to collect, process, store, and dispose of potentially radioactive wastes. A small portion of the system connected to the RHR system maintains the RHR system pressure boundary.The RDW system has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related SSCs in the RDW system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-32 identifies the following RDW system component types within the scopeof license renewal and subject to an AMR:
* bolting
* orifice
* piping
* pump casing
* strainer housing
* tank
* tubing
* valve bodyThe RDW system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13K.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2, and UFSAR Sections 9.2 and 9.3 using the Tier-2evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LRSection 2.3.
2-118In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13K.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the RDW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13L Equipment Retired in Place2.3.3.13L.1  Summary of Technical Information in the Application This system designation in the component database is for obsolete equipment. It has nosafety-related components and no system intended functions; however, certain components supporting safety-related components are required to maintain structural integrity.The failure of nonsafety-related SSCs of equipment retired in place (RIP) potentially couldprevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-35 identifies the following component types of equipment RIP within thescope of license renewal and subject to an AMR:
* bolting
* piping
* valve bodyThe equipment RIP component intended function within the scope of license renewal is toprovide pressure boundary.2.3.3.13L.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 using the Tier-1 evaluation methodology describedin SER Section 2.3. and the guidance described in SRP-LR Section 2.3.In conducting its review, staff evaluated the system functions described in the LRA and UFSARto verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).
2-1192.3.3.13L.3  ConclusionThe staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the equipment RIP components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13M Reactor Water Clean-Up2.3.3.13M.1  Summary of Technical Information in the Application The RWCU system maintains high reactor water purity to limit chemical and corrosive actionand to remove corrosion products to limit impurities available to activate neutron flux. The RWCU system purifies the reactor coolant water by continuously removing a portion of the reactor recirculation flow from the suction side of a recirculation pump, sending the removedflow through filter-demineralizer units to undergo mechanical filtration and ion exchange processes, and returning the processed fluid back to the reactor via the feedwater line.The RWCU system has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related SSCs in the RWCU system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-36 identifies the following RWCU system component types within the scopeof license renewal and subject to an AMR:
* bolting
* filter housing
* heat exchanger (shell)
* orifice
* piping
* pump casing
* strainer housing
* tank
* tubing
* valve bodyThe RWCU system component intended function within the scope of license renewal is toprovide pressure boundary.2.3.3.13M.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 4.9 using the Tier-2 evaluationmethodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any 2-120components with intended functions as required by 10 CFR 54.4(a). The staff then reviewedthose components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.13.2 identified an area in which additional informationwas necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.The staff stated that license renewal drawing LRA-G-191178-SH-01-0, at location D-4, showsthe common elbow differential flow element upstream piping and high side instrument lines connected to flow transmitters FT-12-1A and FT-12-1 B as not within the scope of license renewal. A failure of the flow element upstream RWCU piping or common high side instrument line could prevent the flow transmitters from detecting a high flow condition and the subsequent auto isolation of the RWCU isolation valves. The UFSAR states that the high flow auto closure of the RWCU isolation valves prevents excessive loss of reactor coolant and reduces the amount of radioactive material released from the nuclear system caused by an RWCU line break. In RAI 2.3.3.13k-1 dated August 16, 2006, the staff requested that the applicant confirm whether the RWCU high flow auto isolation will occur when negative differential pressure is caused by either failure of the flow element upstream piping or the common high side instrument line. If not, explain why the flow element upstream piping and the common high sideinstrument lines are not shown to be within the scope of license renewal. In its response dated September 20, 2006, the applicant stated that the flow element upstreampiping and the common high side instrument lines are within the scope of license renewal based on the requirements of 10 CFR 54.4(a)(2) and thus are not shown as highlighted on the drawing. As stated in LRA Table 2.3.3.1B, "Description of Nonsafety-Related System Components Subject to Aging Management Review Based on 10 CFR 54.4(a)(2) for Physical Interactions," the nonsafety-related portion of the RWCU system located inside the reactor building is within the scope of license renewal and subject to an AMR. The common elbow differential flow element upstream piping and high side instrument lines connected to flow transmitters FT-12-1A and FT-12-1B are located inside the reactor building and are included in Table 2.3.3-13-36, "Reactor Water Clean-Up (RWCU) System Nonsafety-Related Systems and Components Affecting Safety-Related Systems Components Subject to Aging Management Review." They are listed as component types of piping, tubing and valve body. As discussed in LRA Section 2.1.2.1.3, "Mechanical System Drawings," in-scope components required by 10 CFR 54.4(a)(2) are not highlighted on the drawings.Based on its review, the staff found the applicant response to RAI 2.3.3.13k-1 acceptablebecause the applicant acknowledged that the flow element upstream piping and the common high side instrument lines connected to flow transmitters FT-12-1A and FT-12-1B are within the scope of license renewal and subject to an AMR based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). Therefore, the staff concern described in RAI 2.3.3.13k-1 is resolved.The staff's review of LRA Section 2.3.3.13.2 identified areas in which information provided inthe LRA needed to be confirmed by the NRC Regional Inspection Team to complete the review of the applicant's scoping and screening results.
2-121Inspection Item 2.3.3.13m-1The LRA states that the RWCU system is within the scope of license renewal in accordancewith 10 CFR 54.4(a)(2) because of the potential for physical interaction with safety-related components as described in LRA Table 2.3.3.13-A. The determination of whether a component meets the requirements of 10 CFR 54.4(a)(2) for physical interactions is based on where it is located in a building and its proximity to safety-related equipment or where a structural/seismic boundary exists. This information is not provided on license renewal drawings nor was a detailed description provided in the LRA. Consequently, any omission of RWCU components subject to an AMR cannot be determined. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(2) and all the components subject to an AMR are included in LRA Table 2.3.3-13-36.In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRCLicense Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope. Further, the applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 states that there are no nonsafety-related systems for which the applicant has not identified the nonsafety-related portions of systems which are attached to safety-related systems and required to be in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The applicant also stated that there were no additional components that should be within scope based on 10 CFR 54.4(a) as identified during the NRC Regional Inspection and subsequent applicant reviews.Based on its review, the staff found the above response acceptable because the applicantstated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope in accordance with 10 CFR 54.4(a)(2) and that there were no additional components identified that should be in-scope based on 10 CFR 54.4(a). Therefore, the staff concern regarding the components of the RWCU system described in Inspection Item 2.3.3.13m-1 is resolved.2.3.3.13M.3  Conclusion The staff reviewed the LRA and RAI and inspection item responses to determine whether theapplicant failed to identify any SSCs within the scope of license renewal or subject to an AMR.
The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the RWCU system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1222.3.3.13N Stator Cooling 2.3.3.13N.1  Summary of Technical Information in the Application The stator cooling system cools the stator winding of the main generator. The system permitsgenerator load changes with minimum variation of stator winding temperature. The stator copper is in direct contact with low-conductivity water of automatically-controlled temperature and pressure; therefore, average copper temperature can be kept essentially constant, practically eliminating thermal stress cycling of the insulation.The failure of nonsafety-related SSCs in the stator cooling system potentially could prevent thesatisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-39 identifies the following stator cooling system component types within thescope of license renewal and subject to an AMR:
* bolting
* cooler
* filter housing
* heat exchanger (shell)
* piping
* pump casing
* strainer housing
* tank
* tubing
* valve bodyThe stator cooling system component intended function within the scope of license renewal is toprovide pressure boundary.2.3.3.13N.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 8.2.3.11.2 using the Tier-1evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LRSection 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13N.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant 2-123has adequately identified the stator cooling system components within the scope of licenserenewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13O HD & HV Instruments 2.3.3.13O.1  Summary of Technical Information in the ApplicationThe heater drain (HD) and the heater vent (HV) instruments system provides indication, alarmand control functions for associated systems (heater drains and heater vents). The failure of nonsafety-related SSCs in the HD & HV instruments system potentially couldprevent the satisfactory accomplishment of a safety-related function.LRA Table 2.3.3-13-43 identifies the following HD & HV instruments system component typeswithin the scope of license renewal and subject to an AMR:
* bolting
* piping
* tubing
* valve bodyThe HD & HV instruments system component intended function within the scope of licenserenewal is to provide pressure boundary.2.3.3.13O.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 using the Tier-1 evaluation methodology describedin SER Section 2.3 and the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA to verifythat the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13O.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the HD & HV instruments system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1242.3.3.13P Air Evacuation 2.3.3.13P.1  Summary of Technical Information in the ApplicationThe air evacuation (AE) system evacuates gases from the main turbine and main condenserduring startup and maintains them free of noncondensible gases during operation. The failure of nonsafety-related SSCs in the AE system potentially could prevent thesatisfactory accomplishment of a safety-related function.LRA Table 2.3.3-13-44 identifies the following AE system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* filter housing
* heat exchanger (shell)
* piping
* pump casing
* rupture disk
* strainer housing
* trap
* tubing
* valve bodyThe AE system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13P.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.4 using the Tier-1 evaluationmethodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13P.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the AE system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1252.3.3.13Q Building (Drainage System Components) 2.3.3.13Q.1  Summary of Technical Information in the ApplicationThe building (BLD) system removes operational waste fluids from their points of origin in acontrolled manner and delivers them to a suitable disposal system. The BLD system includes floor drains and the site sewers. This system classification also includes buildings and structures which are evaluated in LRA Section 2.4.The failure of nonsafety-related SSCs in the BLD system potentially could prevent thesatisfactory accomplishment of a safety-related function.LRA Table 2.3.3-13-46 identifies the following BLD system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* pipingThe BLD component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13Q.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 10.16 using the Tier-1evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LRSection 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13Q.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the BLD system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13R Circulating Water Priming 2.3.3.13R.1  Summary of Technical Information in the ApplicationThe circulating water priming (CWP) system provides air evacuation from the discharge side ofthe main condenser. The system ensures that air will not hinder circulating water flow by 2-126collecting in the upper portions of the condenser water boxes or in the upper portion of thecirculating water discharge piping. The failure of nonsafety-related SSCs in the CWP system potentially could prevent thesatisfactory accomplishment of a safety-related function.LRA Table 2.3.3-13-47 identifies the following CWP system component types within the scopeof license renewal and subject to an AMR:
* bolting
* piping
* pump casing
* tank
* trap
* tubing
* valve bodyThe CWP system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13R.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.63 using the Tier-1evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LRSection 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13R.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the CWP system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13S Extraction Steam 2.3.3.13S.1  Summary of Technical Information in the ApplicationThe extraction steam (ES) system supplies steam to the shell side of various feedwater heatersfor condensate and feedwater heating. Extraction steam is piped from the main turbine casing and cross-around piping to the shells of two parallel strings of reactor feedwater heaters.
2-127The failure of nonsafety-related SSCs in the ES system potentially could prevent thesatisfactory accomplishment of a safety-related function.LRA Table 2.3.3-13-48 identifies the following ES system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* expansion joint
* orifice
* piping
* tubing
* valve bodyThe ES system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13S.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.5.4.3 using the Tier-1evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LRSection 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13S.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the ES system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13T Heater Drain 2.3.3.13T.1  Summary of Technical Information in the ApplicationThe heater drain (HD) system provides proper level and control for the moisture separator andfeedwater heaters by providing drain capability to the main condenser. Condensate drainage from the drain coolers of each feedwater heater flows to the next lower pressure heater by means of pressure differential between successive heaters. Condensate flow may be aided by a heater drain pump between the two lowest pressure heaters in each string.
2-128The failure of nonsafety-related SSCs in the HD system potentially could prevent thesatisfactory accomplishment of a safety-related function.LRA Table 2.3.3-13-49 identifies the following HD system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* piping
* pump casing
* tank
* tubing
* valve bodyThe HD system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13T.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.8.3.2 using the Tier-1evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LRSection 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13T.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the HD system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13U Heater Vent 2.3.3.13U.1  Summary of Technical Information in the ApplicationThe heater vent (HV) system provides venting of non-condensable gases back to the maincondenser. The failure of nonsafety-related SSCs in the HV system potentially could prevent thesatisfactory accomplishment of a safety-related function.
2-129LRA Table 2.3.3-13-50 identifies the following HV system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* orifice
* piping
* tank
* tubing
* valve bodyThe HV system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13U.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2, the Tier-1 evaluation methodology described inSER Section 2.3, and the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA to verifythat the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13U.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the HV system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13V Make-up Demineralizer 2.3.3.13V.1  Summary of Technical Information in the ApplicationThe make-up demineralizer (MUD) system provides a supply of treated water that may be usedas make-up for the station and reactor cycles. The MUD system consists of one train that consists of a cation, anion, and a mixed bed ion exchanger. The failure of nonsafety-related SSCs in the MUD system potentially could prevent thesatisfactory accomplishment of a safety-related function.
2-130LRA Table 2.3.3-13-53 identifies the following MUD system component types within the scopeof license renewal and subject to an AMR:
* bolting
* filter housing
* piping
* pump casing
* tank
* tubing
* valve bodyThe MUD system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13V.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 10.13 using the Tier-1evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LRSection 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13V.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the MUD system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13W Seal Oil 2.3.3.13W.1  Summary of Technical Information in the ApplicationThe seal oil (SO) system provides shaft sealing for the main generator.
The failure of nonsafety-related SSCs in the SO system potentially could prevent thesatisfactory accomplishment of a safety-related function.LRA Table 2.3.3-13-55 identifies the following SO system component types within the scope oflicense renewal and subject to an AMR:
* bolting 2-131
* filter housing
* piping
* pump casing
* sight glass
* tank
* tubing
* valve bodyThe SO system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13W.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.23 using the Tier-1evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LRSection 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).
2.3.3.13W.3  ConclusionThe staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the SO system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13X Turbine Building Closed Cooling Water 2.3.3.13X.1  Summary of Technical Information in the ApplicationThe turbine building closed cooling water (TBCCW) system supplies demineralized water tocool various nonsafety-related auxiliary equipment located in the turbine building in support of power generation. The system consists of two pumps, two 100 percent capacity heat exchangers and the necessary controls, piping, and instrumentation. Station service water provides the cooling medium for the TBCCW heat exchangers, however, it is automatically isolated if service water pressure drops to a present value which could occur under a condition of concurrent loss-of-coolant accident and loss of offsite power. No essential equipment is cooled by the TBCCW system.The failure of nonsafety-related SSCs in the TBCCW system potentially could prevent thesatisfactory accomplishment of a safety-related function.
2-132LRA Table 2.3.3-13-56 identifies the following TBCCW system component types within thescope of license renewal and subject to an AMR:
* bolting
* heat exchanger (shell)
* piping
* pump casing
* tank
* tubing
* valve bodyThe TBCCW system component intended function within the scope of license renewal is toprovide pressure boundary.2.3.3.13X.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 10.10 using the Tier-1evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LRSection 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13X.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the TBCCW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13Y Main Turbine Generator 2.3.3.13Y.1  Summary of Technical Information in the ApplicationThe main turbine generator (TG) system converts the thermodynamic energy of steam intoelectrical energy for use on the transmission network and the station auxiliary busses. The failure of nonsafety-related SSCs in the TG system potentially could prevent thesatisfactory accomplishment of a safety-related function.
2-133LRA Table 2.3.3-13-57 identifies the following TG system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* filter housing
* piping
* pump casing
* turbine casing
* tubing
* valve bodyThe TG system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13Y.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.2 using the Tier-1 evaluationmethodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13Y.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the TG system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13Z Turbine Lube Oil 2.3.3.13Z.1  Summary of Technical Information in the ApplicationThe turbine lube oil (TLO) system provides lube oil for lubrication of the main turbine.
The failure of nonsafety-related SSCs in the TLO system potentially could prevent thesatisfactory accomplishment of a safety-related function.LRA Table 2.3.3-13-58 identifies the following TLO system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* filter housing 2-134
* heat exchanger (shell)
* piping
* pump casing
* strainer casing
* tank
* tubing
* valve bodyThe TLO system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13Z.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.2.3 using the Tier-1evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LRSection 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13Z.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the TLO system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.13AA Hydrogen Water Chemistry 2.3.3.13AA.1  Summary of Technical Information in the ApplicationThe hydrogen water chemistry (HWC) system mitigates the chemical conditions that allowIGSCC in the recirculation piping and reactor vessels internals. The HWC system injects hydrogen into the reactor feedwater at the suction of the feedwater pumps.The failure of nonsafety-related SSCs in the HWC system potentially could prevent thesatisfactory accomplishment of a safety-related function.LRA Table 2.3.3-13-51 identifies the following HWC system component types within the scopeof license renewal and subject to an AMR:
* bolting
* piping 2-135
* tubing
* valve bodyThe HWC system component intended function within the scope of license renewal is to providepressure boundary.2.3.3.13AA.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Sections 4.2.5, 11.8.3.1 and K.4.7. using the evaluation methodology described in SER Section 2.3 and the guidance described inSRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.3.13AA.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the HWC system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).The remaining systems shown in LRA Table 2.3.3.13-A as within the scope of license renewalwith potential for physical interaction with safety-related components are addressed elsewhere in other LRA sections listed here:
* 2.3.1CRD
* 2.3.1HCUs
* 2.3.1NB
* 2.3.2.1RHR
* 2.3.2.2CS
* 2.3.2.4HPCI
* 2.3.2.5CST
* 2.3.2.5RCIC
* 2.3.2.6SBGT
* 2.3.3.1SLC
* 2.3.3.2SW
* 2.3.3.2RHRSW
* 2.3.3.3RBCCW
* 2.3.3.4DG and auxiliaries
* 2.3.3.4DLO
* 2.3.3.5FPC
* 2.3.3.5FPC filter demineralizer 2-136
* 2.3.3.5SBFPC
* 2.3.3.6FO
* 2.3.3.7IA
* 2.3.3.7N 2
* 2.3.3.8fire protection
* 2.3.3.10HB
* 2.3.3.10HVAC
* 2.3.3.11containment air dilution
* 2.3.3.11PASS
* 2.3.3.11PCAC
* 2.3.4.2condensate2.3.4  Steam and Power Conversion SystemsIn LRA Section 2.3.4, the applicant identified the SCs of the steam and power conversionsystems that are subject to an AMR for license renewal.The applicant described the supporting SCs of the steam and power conversion systems in thefollowing LRA Sections:
* 2.3.4.1auxiliary steam
* 2.3.4.2condensate
* 2.3.4.3main steam
* 2.3.4.4101 (main steam, extraction steam, and auxiliary steam instruments)
The staff's review findings regarding LRA Sections 2.3.4.1 - 2.3.4.4 are presented in SER Sections 2.3.4.1 - 2.3.4.4, respectively.2.3.4.1  Auxiliary Steam2.3.4.1.1  Summary of Technical Information in the Application LRA Section 2.3.4.1 describes the auxiliary steam (AS) system, which provides steam from MSpiping to the steam jet air ejector to maintain main condenser vacuum. The AS system consists of the steam jet air ejector and associated equipment.The failure of nonsafety-related SSCs in the AS system potentially could prevent thesatisfactory accomplishment of a safety-related function. LRA Tables 2.3.4-1and 2.3.3-13-45 identify the AS system component types within the scope oflicense renewal and subject to an AMR:
* bolting
* condenser
* expansion joint
* heat exchanger (shell)
* heat exchanger (tubes)
* piping
* orifice 2-137
* strainer housing
* steam trap
* thermowell
* tubing
* valve bodyThe AS system component intended functions within the scope of license renewal include thefollowing:
* pressure boundary
* holdup and plateout of fission products2.3.4.1.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.1 and UFSAR Section 11.4 using the Tier-2 evaluationmethodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.4.1.3  Conclusion The staff reviewed the LRA and accompanying license renewal drawings to determine whetherthe applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the AS system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4.2  Condensate2.3.4.2.1  Summary of Technical Information in the Application LRA Section 2.3.4.2 describes the condensate system, which receives condensed steam fromthe condenser and supplies it to the reactor feedwater system as well as such other components and systems as the air ejector condensers, steam packing exhausters, and CRD pumps. The condensate system consists of a single train with three parallel pumps drawing condensate from the two main condenser hotwells and includes the main condenser. During normal operation, all three pumps provide sufficient condensate flow capacity and net positive suction head to the reactor feedwater pumps during full power operation. Condensate flow to the reactor feed pumps passes through two parallel low-pressure feedwater heater strings, each with three heaters. Condensate flow exiting the low-pressure heaters is provided to a common reactor feed pump suction header.
2-138The failure of nonsafety-related SSCs in the condensate system potentially could prevent thesatisfactory accomplishment of a safety-related function. LRA Tables 2.3.4-1 and 2.3.3-13-2 identify the following condensate component types withinthe scope of license renewal and subject to an AMR:
* bolting
* condenser
* expansion joint
* heat exchanger (shell)
* heat exchanger (tubes)
* orifice
* piping
* pump casing
* steam trap
* strainer housing
* tank
* thermowell
* tubing
* valve bodyThe condensate system component intended functions within the scope of license renewalinclude the following:
* pressure boundary
* holdup and plateout of fission products2.3.4.2.2  Staff Evaluation The staff reviewed LRA Sections 2.3.4.2 and 2.3.3.13, and UFSAR Section 11.8 using theTier-2 evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.4.2.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCswithin the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the condensate system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1392.3.4.3  Main Steam2.3.4.3.1  Summary of Technical Information in the Application LRA Section 2.3.4.3 describes the MS system, which completes the transmission of steam fromthe seismic Class I steam piping to the main turbine at a controlled pressure during normal operation. The MS system consists of nonsafety-related components. (The nuclear boiler system contains the seismic Class I portion of the MS system which extends from the reactor vessel to the restraint at the second MS isolation valve. The system consists of the non-seismic Class I components beyond this point.) The MS system includes the turbine stop and control valves. A low-point drain line is downstream of each turbine control valve continuously draining the steam line low points through an orificed header to the condenser hotwell. The MS system has the ability to bypass the turbine when necessary. The main turbine bypass system has two valve chests, each with five automatically operated regulating bypass valves proportionally controlled by the turbine pressure regulator and control system. The bypass system opens whenever the amount of steam admitted into the turbine is less than that generated by the reactor. The MS system provides main turbine sealing steam.The failure of nonsafety-related SSCs in the MS system potentially could prevent thesatisfactory accomplishment of a safety-related function. LRA Tables 2.3.4-1and 2.3.3-13-52 identify the following MS system component types withinthe scope of license renewal and subject to an AMR:
* bolting
* condenser
* expansion joint
* heat exchanger (shell)
* heat exchanger (tubes)
* orifice
* piping
* steam trap
* strainer housing
* thermowell
* tubing
* valve bodyThe MS system component intended functions within the scope of license renewal include thefollowing:
* pressure boundary
* holdup and plateout of fission products 2-1402.3.4.3.2  Staff EvaluationThe staff reviewed LRA Section 2.3.4.3 and UFSAR Sections 11.4 and 11.5 using the Tier-2evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.In conducting its review, staff evaluated the system functions described in the LRA and UFSARto verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.4.3.3  Conclusion The staff reviewed the LRA and accompanying license renewal drawings to determine whetherthe applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the MS system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4.4  101 (Main Steam, Extraction Steam, and Auxiliary Steam Instruments)2.3.4.4.1  Summary of Technical Information in the Application LRA Section 2.3.4.4 describes the 101 system (main steam, extraction steam, and auxiliarysteam instruments), which provides indication, alarm, and control functions for its associated systems. This system code includes various instrumentation components for main steam, extraction steam, and auxiliary steam. Although the 101 system consists mainly of EIC components, certain mechanical instrumentation components are included as well.The failure of nonsafety-related SSCs in the 101 system (main steam, extraction steam, andauxiliary steam instruments) potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.4-1 identifies the following 101 system (main steam, extraction steam, andauxiliary steam instruments) component types within the scope of license renewal and subject to an AMR:
* bolting
* condenser
* orifice
* expansion joint
* heat exchanger (tubes)
* piping
* strainer housing
* thermowell
* steam trap 2-141
* tubing
* valve bodyThe 101 (main steam, extraction steam, and auxiliary steam instruments) component intendedfunctions within the scope of license renewal include the following:
* pressure boundary
* holdup and plateout of fission products2.3.4.4.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.4 using the Tier-1evaluation methodology described inSER Section 2.3 and the guidance in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.3.4.4.3  Conclusion The staff reviewed the LRA and accompanying license renewal drawings to determine whetherthe applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the 101 (main steam, extraction steam, and auxiliary steam instruments) components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4  Scoping and Screening Results: StructuresThis section documents the staff's review of the applicant's scoping and screening results for structures. Specifically , this section discusses:
* primary containment
* reactor building
* intake structure
* process facilities
* yard structures
* bulk commoditiesIn accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive,long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff's review focused on the implementation results. This focus allowed the staff to confirm that there were no omissions of SCs that meet the scoping criteria and are subject to an AMR.
2-142The staff's evaluation of the information in the LRA was the same for all structures. Theobjective was to determine whether the applicant has identified, in accordance with 10 CFR 54.4, components and supporting structures for structures that appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant's screening results to verify that all passive, long-lived components were subject to an AMR as required by 10 CFR 54.21(a)(1).In its scoping evaluation, the staff reviewed the applicable LRA sections and componentdrawings, focusing on components that have not been identified as within the scope of license renewal. The staff reviewed relevant licensing basis documents, including the UFSAR, for each structure to determine whether the applicant has omitted from the scope of license renewal components with intended functions as required by 10 CFR 54.4(a). The staff also reviewed the licensing basis documents to determine whether the LRA specified all intended functions asrequired by 10 CFR 54.4(a). The staff requested additional information to resolve any omissions or discrepancies identified.After its review of the scoping results, the staff evaluated the applicant's screening results. Forthose SCs with intended functions, the staff sought to determine whether: (1) the functions are performed with moving parts or a change in configuration or properties or (2) the SCs are subject to replacement after a qualified life or specified time period, as required by 10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). The staff requested additional information to resolve any omissions or discrepancies identified.2.4.1  Primary Containment 2.4.1.1  Summary of Technical Information in the ApplicationLRA Section 2.4.1 describes the primary containment, which limits the release of fissionproducts in postulated design basis accidents so offsite doses do not exceed the values specified in 10 CFR 50.67. Located inside the reactor building, the primary containment is a General Electric Mark I containment with a drywell (which encloses the reactor vessel and recirculation system), a pressure suppression chamber (commonly known as the torus), and a connecting vent system. When operating at power, the containment is flooded with N 2 topreclude the availability of oxygen. The drywell surrounds the reactor vessel and primary systems. The torus, containing water, is below the drywell and the vent system connecting it to the drywell terminates below the water surface. Access to the drywell is by its steel drywell head and personnel hatch as well as a double door air lock, equipment hatch, and one CRD access hatch. Access to the torus is by two personnel hatches. The primary containment components include the drywell, the torus, the reactor vessel and drywell bellows, and the shield wall. The drywell is a carbon steel structure that houses the reactor pressure vessel and its components.
A reinforced concrete support structure, founded on bedrock, is part of the drywell support system. The torus is a toroid-shaped carbon steel pressure vessel below and encircling the drywell. The reactor vessel refueling bulkhead has two stainless steel bellows with backing plates, spring seals, and removable guard rings. The drywell to reactor building bellows assembly is similar to that of the reactor vessel refueling bulkhead. The shield wall (also known as the sacrificial shield wall) is a high-density, steel-reinforced, concrete cylindrical structure surrounding the vessel. The concrete is contained by inner and outer steel liner plates that also 2-143attach various system supports. The sacrificial shield wall provides lateral support for thereactor vessel to accommodate both seismic forces and jet forces from the breakage of any pipe attached to the vessel.The primary containment has safety-related components relied upon to remain functional duringand following DBEs. The failure of nonsafety-related primary containment SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the primary containment performs functions that support fire protection.LRA Table 2.4-1 identifies the following primary containment component types within the scopeof license renewal and subject to an AMR:
* steel and other metals
* concrete
* elastomers and other materials
* fluoropolymers and lubrite sliding surfacesThe primary containment component intended functions within the scope of license renewalinclude the following:
* shelter or protection to safety-related equipment, including radiation shielding and pipewhip restraint
* protective barrier for flood events
* heat sink during SBO or DBAs
* missile barrier
* pressure boundary
* structural or functional support for safety-related equipment2.4.1.2  Staff EvaluationThe staff reviewed LRA Section 2.4.1 and UFSAR Sections 5.1.2 and 5.2 using the evaluationmethodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4, "Scopingand Screening Results: Structures."The staff evaluated the structural component functions described in the LRA and UFSAR toverify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.4.1.3  ConclusionThe staff reviewed the LRA and related structural components to determine whether theapplicant failed to identify any SSCs within the scope of license renewal or subject to an AMR.
2-144The staff finds no such omissions. On the basis of its review, the staff concludes that there isreasonable assurance that the applicant has adequately identified the primary containment components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.2  Reactor Building 2.4.2.1  Summary of Technical Information in the ApplicationLRA Section 2.4.2 describes the reactor building, which in design basis accidents containsleakage of airborne fission products to the environment within the dose limits specified in 10 CFR 50.67 and supports and protects the reactor and its systems. The reactor building completely encloses the primary containment and houses the refueling and reactor servicing equipment (platforms and cranes), new and spent fuel storage facilities, reactor core isolation cooling system, SBGT system, reactor cleanup demineralizer system, SLC system, CRD system equipment, reactor core and containment cooling systems, and electrical equipment components. The seismic Class I reactor building is constructed of monolithic reinforced concrete floors and walls up to the refueling level and of steel framing covered by insulated sealed siding and roof decking above. The siding and roofing can withstand limited internal overpressure before it is relieved by venting through blowout panels. A biological shield wall, part of the reactor building, encircles the primary containment, protects the containment vessel and the reactor system against potential external missiles, and shields personnel to reduce dose. The reactor building bridge crane, which services the reactor and the refueling area, isdesigned seismic Class II with supports designed seismic Class I. The crane bridge and trolley wheels have seismic holddown lugs for crane stability in a hypothetical maximum earthquake.
The new fuel storage vault, part of the seismic Class I reactor building, houses new fuel storage racks, each designed as seismic Class I while loaded with fuel. The spent fuel storage pool in the reactor building is lined with stainless steel. The pool liner is seam-welded ASTM-A240 Type 304 stainless steel with pipe sleeves welded to both sides of the liner plate. The spent fuelstorage racks are assemblies of individual storage cells consisting of Type 304L stainless steel boxes welded together. The seismic Class I refueling platform, the principal means of transporting fuel assemblies back and forth, travels on tracks extending along each side between the reactor well and the storage pool. The reactor building has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related reactor building SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the reactor building performs functions that support fire protection, ATWS, and SBO.LRA Table 2.4-2 identifies the following reactor building component types within the scope oflicense renewal and subject to an AMR:
* steel and other metals
* concrete 2-145The reactor building component intended functions within the scope of license renewal includethe following:
* shelter or protection to safety-related equipment, including radiation shielding and pipewhip restraint
* rated fire barrier to confine or retard a fire from spreading
* protective barrier for flood events
* missile barrier
* pressure boundary
* structural or functional support to nonsafety-related equipment the failure of which couldimpact safety-related equipment
* structural or functional support for safety-related equipment2.4.2.2  Staff EvaluationThe staff reviewed LRA Section 2.4.2 and UFSAR Sections 5.3, 10.4, and 12.2.2 using theevaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.The staff evaluated the structural component functions described in the LRA and UFSAR toverify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).2.4.2.3  ConclusionThe staff reviewed the LRA and related structural components to determine whether theapplicant failed to identify any SSCs within the scope of license renewal or subject to an AMR.
The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the reactor building components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.3  Intake Structure 2.4.3.1  Summary of Technical Information in the ApplicationLRA Section 2.4.3 describes the intake structure, which supports and protects equipment thatdraws water from the intake canal, located east of the station on the riverbank and divided into two rooms: the SW pump room (which also contains the diesel and electric fire pumps) and the circulating water pump room. The room housing the SW pumps is seismic Class I; the other is seismic Class II. The reinforced concrete and steel intake structure is founded entirely onbedrock. It has three pump bays for the vertical circulating water pumps, two SW bays for four SW pumps and two fire water pumps, three roller gates, and one sluice gate. Recirculation of 2-146warm discharge water by a concrete pipe connecting the discharge structure to the intakestructure keeps the intake bays and SW bays free of ice. All bays have trash racks and stop log guides, traveling screens, and fine screen guides. Interconnection of the three pump bays is by removal of stop logs in center walls.The intake structure has safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related intake structure SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the intake structure performs functions that support fire protection.LRA Table 2.4-3 identifies the following intake structure component types within the scope oflicense renewal and subject to an AMR:
* steel and other metals
* concreteThe intake structure component intended functions within the scope of license renewal includethe following:
* shelter or protection to safety-related equipment, including radiation shielding and pipewhip restraint
* rated fire barrier to confine or retard a fire from spreading
* protective barrier for flood events
* missile barrier
* structural or functional support to nonsafety-related equipment the failure of which couldimpact safety-related equipment
* structural or functional support for equipment required to meet fire protection,environmental qualification, pressurized thermal shock (PTS), ATWS, or SBO regulations
* structural or functional support for safety-related equipment2.4.3.2  Staff EvaluationThe staff reviewed LRA Section 2.4.3 and UFSAR Sections 10.6.5, 10.11.3, and 12.2.6 usingthe evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.The staff evaluated the structural component functions described in the LRA and UFSAR toverify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).
2-147In RAI 2.4.3-1 dated August 3, 2006, the staff stated that Table 2.4.3 does not include thesluice gate, roller gates, trash racks, stop log guides, traveling screens, and fine screen guides within the intake structure, and the concrete pipe that connects the intake structure to the discharge structure. The staff requested that the applicant provide justification for not including them within the scope of license renewal. In its response dated September 5, 2006, the applicant provided the following response:Sluice gates and roller gates The roller gates isolate the circulating water bays from the river and have nolicense renewal intended function. The sluice gate is used for de-icing. De-icing supports normal plant operation and is not credited for emergency operation, since warm circulating water flow would not be available with a loss of offsite power. The gates have no license renewal intended function and are not included in LRA Table 2.4-3. Trash racks and traveling screens The trash racks and traveling screens remove debris from the circulating andSW system flow path to prevent plugging of the condenser water box inlets and loss of SW flow. The circulating water bays and the SW bays have separate flow paths sharing a common wall. The trash racks prevent the high circulating water velocity from drawing large debris into the circulating water bays during normal plant operation. However, during emergency operations, the circulating water pumps are unnecessary and, in fact, may be unavailable due to a loss of offsite power. For normal and emergency operations, the SW pumps draw a much lower volume of water through the SW bays. The lower flow rates of the SW system are insufficient to transport large debris that could prevent the traveling screens from passing adequate flow to the SW pumps to allow for safe shutdown. Therefore, trash racks do not provide a license renewal intended function as required by 10 CFR 54.4(a)(1), (a)(2) or (a)(3).
 
The structural supports for the traveling screens are part of the screen-house structure, which is within the scope of license renewal and subject to an AMR.
The traveling screens themselves perform their function with moving parts and a change in configuration and are therefore, not subject to an AMR in accordance with 10 CFR 54.21 (a)(l)(i), and are not included in LRA Table 2.4-3.Stop log guides and fine screen guides The stop log guides and fine screen guides do not perform a license renewalintended function. The purpose of the stop log guides is to hold temporary stop logs in place to allow inspections or maintenance. The fine screen guides do not perform a license renewal intended function because a fine screen is not utilized at VYNPS. Therefore, the stop log and fine screen guides do not provide a license renewal intended function as required by 10 CFR 54.4(a)(1), (a)(2) or (a)(3).
2-148Concrete pipe The concrete pipe connecting the intake structure to the discharge structureprovides recirculation of warm condenser circulating water to keep the circulatingwater intake bays and SW bays free of ice. De-icing supports normal plant operation and is not credited for emergency operation, since warm circulating water flow would not be available with a loss of offsite power. Therefore, the concrete pipe does not provide a license renewal intended function as required by 10 CFR 54.4(a)(1), (a)(2) or (a)(3). Based on its review, the staff finds the applicant's response to RAI 2.4.3-1 acceptable becausethe applicant has provided sufficient explanations for the function of the sluice gate, roller gates, trash racks, stop log guides, traveling screens and fine screen guides within the intake structure, and the concrete pipe that connects the intake structure to the discharge structure, and the basis of their exclusion from the license renewal intended function requirements of 10 CFR 54.4(a)(1), (2) or (3). The staff's concern described in RAI 2.4.3-1 is resolved.2.4.3.3  ConclusionThe staff reviewed the LRA and related structural components to determine whether theapplicant failed to identify any SSCs within the scope of license renewal or subject to an AMR.
The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the intake structure components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.4  Process Facilities 2.4.4.1  Summary of Technical Information in the ApplicationLRA Section 2.4.4 describes the process facilities, buildings or structures designated as eitherseismic Class I or II for power generation and supporting processes with concrete floor slabs, structural steel floors, and platforms as required supported by concrete or structural steel columns, base slabs, and walls. Process facilities include alternate cooling cells and the cooling tower No. 2 deep basin, the control building, the plant stack, and the turbine building. Alternate cooling cell No. 2-1 and the cooling tower No. 2 deep basin provide a heat sink to remove decay heat and sensible heat from the primary system so the reactor can be shut down safely when the SW pumps are not available. Alternate cooling cell No. 2-1, adjoining cooling cell 2-2, and the cooling tower No. 2 deep basin, support and protect structures necessary for the heat sink. The control building houses instrumentation and switches required for station operation withmajor instrumentation in the main control room. The cable vault and east and west switchgear rooms occupy the lower levels of the building. The plant stack (or main stack) discharges gases to the atmosphere from portions of the turbine building, reactor building, RDW building, SBGT system, and advanced off-gas system. The height of the stack ensures an elevated release and 2-149an enclosure at its base contains monitoring equipment. The turbine building houses the TGand auxiliaries including the condensate, feedwater, DG, and water treatment systems. Portions of the turbine building support and protect the EDGs and FO day tank areas.The process facilities have safety-related components relied upon to remain functional duringand following DBEs. The failure of nonsafety-related process facility SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the process facilities perform functions that support fire protection.LRA Table 2.4-4 identifies the following process facilities component types within the scope oflicense renewal and subject to an AMR:
* steel and other metals
* concrete
* elastomer and other materialsThe process facilities component intended functions within the scope of license renewal includethe following:
* shelter or protection to safety-related equipment, including radiation shielding and pipewhip restraint
* rated fire barrier to confine or retard a fire from spreading
* protective barrier for flood events
* heat sink during SBO or DBAs
* missile barrier
* pressure boundary
* structural or functional support to nonsafety-related equipment the failure of which couldimpact safety-related equipment
* structural or functional support for equipment required to meet fire protection,environmental qualification, PTS, ATWS, or SBO regulations
* structural or functional support for safety-related equipment2.4.4.2  Staff EvaluationThe staff reviewed LRA Section 2.4.4 and UFSAR Sections 10.8, 11.9, 12.2.3, 12.2.4, 12.2.5,and 12.2.6.4 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.The staff evaluated the structural component functions described in the LRA and UFSAR toverify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).
2-150In RAI 2.4.4-1 dated August 3, 2006, the staff stated that Table 2.4-4 lists "Structural steel" as acomponent, and "Structural steel: beams, columns, plates " as another component. The staff requested that the applicant provide clarification for the two different components. In its response dated September 5, 2006, the applicant provided the following response:Table 2.4.4 lists these two different components.
 
"Structural steel: beams, columns, plates" is defined as:
* substructure or superstructure steel that is part of the primary structuralsupport function of a building or structure, such as structural columns, support girders, beams, plates, connections, roofing joists, purlins, and wind bracing. "Structural steel" is defined as:
* steel which does not perform a primary structural integrity function for abuilding but does provide secondary structural support for equipment or components within the building, or it may provide protection around openings in floors or walls and metal decking on the bottom of reinforced concrete floor slabs. Structural steel includes items such as grating, grating supports, embedded channels, angles, frames, and embedded
 
inserts such as Unistrut TM. Based on its review, the staff finds the applicant's response to RAI 2.4.4-1 acceptable becauseit distinguishes the primary structural support function from a secondary structural support function of steel members. The staff's concern described in RAI 2.4.4-1 is resolved.In Table 2.4-4, cooling tower cell No. 2-1, cooling tower cell No. 2-2, and foundation (coolingtower No. 2 deep basin) are listed as subject to an aging management review. On August 21, 2007, a portion of cooling tower cell No. 2-4 collapsed. The staff required verification as to whether the affected cells should be in the scope of license renewal and whether scoping for license renewal has been appropriately conducted with respect to the cooling towers.In RAI 2.4.4-2 dated August 29, 2007, the staff requested that the applicant provide the resultsof the review performed to determine the impact of the circulating water piping, pipe supports, and west cooling tower cell (2-4) failures on license renewal scoping, screening, and applicable aging management programs. The staff also requested the applicant to include the following information:A.A conclusion and basis as to whether the scoping results documented in the LRA, whichinitially determined that 9 of the11 west cooling tower cells were not within the scope of license renewal, are still valid.B.If found that the west cooling tower cells (2-3 through 2-11) are within the scope oflicense renewal,  provide the following:
2-151I.The potential effect of a circulating water piping, pipe supports, or structuralfailure of the nonsafety-related west cooling tower cells (2-3 through 2-11), which were not included within the scope of license renewal, on safety-related systems, structures, and components (in accordance with 10 CFR 54.4(a)(2)). Include the potential effect of debris entering the deep basin beneath the cooling tower. II.The details of any age related degradation which caused the failure of thecirculating water piping, pipe supports, and west cooling tower cell. Include the results of the piping and pipe supports inspection related to the current failure and any previously performed, and a description of the identified aging mechanism(s).C.Any impact on the aging management programs for circulating water piping, pipesupports, or cooling tower cells.In letters dated September 27 and October 18, 2007, the applicant provided the followingresponse:Cooling Tower Background InformationVYNPS utilizes once-through condenser cooling from the Connecticut Riversupplemented by two forced draft cooling towers. Each tower consists of eleven cells, each cell equipped with its own forced draft fan. One cell in the west cooling tower, CT 2-1, provides a safety related function as the heat sink for the Residual Heat Removal Service Water system (RHRSW) in the Alternate Cooling System (ACS) mode and is constructed as a Seismic Class I structure.
The adjacent cell, CT 2-2, is also designed and constructed as a Seismic Class I structure to prevent adversely impacting the structural integrity of CT 2-1 during a seismic event. CT 2-1 and CT 2-2 structures have similar construction as the other coolingtower cells for dead weight loads, but a more robust bracing system to withstand wind and seismic loading. They are constructed from high quality timber and use stainless steel hardware for all bolted connections. The structural columns were refurbished during the 1980's, followed by end wall refurbishment between 2002 and 2007. As required for activities associated with any safety-related and Seismic Class I systems, structures, and components (SSCs), the inspections and repairs on cooling tower cells CT 2-1 and CT 2-2 receive additional oversight by the site Engineering, Maintenance, and Quality Assurance (QA) groups.
* Different design. Safety-related Cell CT 2-1 and Seismic Class I CellCT 2-2 design includes additional 4"x4" cross-bracing to withstand wind and seismic loading. In CT 2-1, some of the additional bracing is heavier 4" x 6" material.
* Different material specifications. Hardware for CT 2-1 and CT 2-2 isstainless steel, while the other towers may use carbon or galvanized 2-152steel. The stainless steel hardware minimizes potential iron salt attack atthe bolted structural connections.
* Different level of quality. CT 2-1 and CT 2-2 are subject to the higherlevels of oversight afforded to safety-related and Seismic Class Istructures. The higher level of quality results in application of the station corrective action program to evaluate deficiencies and effect appropriate corrective actions.
* Different maintenance history. Because of their safety significance andhigher level of quality, CT 2-1 and CT 2-2 have had more refurbishmentduring the past ten years than the other tower cells. During this period, the end wall of CT 2-1 and the partition walls of CT 2-1 and CT 2-2 have been replaced, including the vertical columns and structural hardware.
The original end walls and partition walls remain in many of the non-Seismic Class I cells.Response to Part A:Cooling tower cells CT 2-1 and CT 2-2 are the only cells in the scope of licenserenewal. Failures of the other cells will not prevent satisfactory accomplishment of a safety function identified in 10 CFR 54.4(a)(1). The scoping results documented in the LRA remain valid. See the response to part B for further discussion of potential failures.Cooling tower cell CT 2-1, which is part of the circulating water system, has the10 CFR 54.4(a)(1) and (a)(3) intended function to support operation of the alternate cooling system by providing an alternate means of heat removal in the unlikely event that the service water pumps become inoperable. Therefore, CT 2-1 is in the scope of license renewal and subject to aging management review. Cell CT 2-1 itself and associated components of the residual heat removal service water (RHRSW) system fulfill the intended function. The credited RHRSW system components in CT 2-1 are the 24" carbon steel suction piping located in the RHRSW suction pit and the 16" and 20" carbon steel distribution piping that discharges water into the cooling tower from the RHRSW pumps. Aging management review results for RHRSW system components at CT 2-1 are provided in LRA Table 3.3.2-2. Circulating water piping is not relied on to perform the license renewal intended function of supporting alternate cooling system operation. The circulating water system piping has no other system intended functions in scope for 54.4(a)(1) or (a)(3). It does have a 54.4(a)(2) intended function to maintain integrity of nonsafety-related components such that no physical interaction with safety-related components could prevent satisfactory accomplishment of a safety function.
2-153Response to Part BSubpart I:  As indicated in the LRA and in response to Part A, west cooling tower cells CT 2-1 and CT 2-2 are within the scope of license renewal. The failure of cooling tower cell CT 2-4 or any other of the cooling tower cells, along with the associated circulating water piping and pipe supports, has no impact on the ability of the in-scope cooling tower cells and the Cooling Tower No. 2 (west cooling tower) deep basin to accomplish safety functions under design basis conditions. Cooling tower cells CT 2-1 and CT 2-2 are seismically designed to ensure that they are not adversely affected by a seismic event or by failure of other cooling tower cells. This design includes "breakaway" connections to the remaining cooling tower cells. These breakaway connections
..... are constructedby cutting the major wooden structural members connecting CT 2-2 to CT 2-3 and splicing them together with weaker materials that will separate in the event of significant seismic loading.For cooling tower cell CT 2-1, the portion of the circulating water system pipingthat is in scope for 54.4(a)(2) is the carbon steel piping outside the tower that supplies water to the tower. This portion of the piping has the potential for spatial interaction with safety-related electrical equipment due to spray or leakage. This carbon steel piping is subject to aging management review as shown in Tables 2.3.3.13-B and 3.3.2.13-9. This carbon steel circulating water system piping transitions to fiberglass upon entering CT 2-1. The fiberglass circulating water piping has no license renewal intended function as discussed below. Therefore, fiberglass circulating water piping is not included in the LRA Section 3.3 tables.
The fiberglass circulating water piping is nonsafety-related and supports nosystem intended functions for 54.4(a)(1) or (a)(3). Pipe supports on this piping are part of the wooden tower structure and are subject to aging management review and included in the Structures Monitoring Program to ensure the piping cannot physically impact safety-related equipment. Following onset of the recent partial failure of CT 2-4, two lengths of the circulating water piping separated at a connecting joint. Failure of vertical wooden structural columns caused the piping to sag and separate at the joint. Managing the effects of aging on the wooden tower structure will prevent a similar piping separation at the joints in CT 2-1.
The seismic analysis shows that the pipe stays intact during a seismic event. No other credible failure mechanisms can cause wholesale failure of the fiberglass piping. Postulated failures involving minor leakage from piping joints could spray or leak water on internal Cell CT 2-1 components. These components are designed for a wetted environment during normal cooling tower operation and as such would not be adversely impacted. As a result, the fiberglass piping cannot prevent satisfactory accomplishment of any of the functions identified in 10 CFR 54.4(a)(1) due to spatial interaction from spray or leakage, and is not in scope and subject to aging management review under 54.4(a)(2). 
 
2-154If the fiberglass piping were subject to aging management review, the agingmanagement review results would be that there are no aging effects requiring management due to the high corrosion resistance of fiberglass which is composed of glass fibers. This is consistent with NUREG-1801, Volume 2, Line V.F-8 that lists no aging effects for glass piping elements in raw water.The cooling tower basin has a storage capacity of 1.45 million gallons that issufficient for seven days of ACS operation. The available capacity assumes that cooling tower cells CT 2-3 through CT 2-9 collapse during a seismic event resulting in an estimated 170,427 gallons of water (equivalent to the volume of all material in these cells) being displaced (lost). The evaluation does not credit the volume of water in basin below cooling tower cells CT 2-10 and CT 2-11. The basin below these two cells is shallow and the small volume of water is conservatively not credited for available capacity. Because the volume of the basin beneath cells CT2-10 and CT2-11 is not credited, a postulated collapse of the wooden structure of these two cells displaces no credited volume.The potential for debris blockage of the ACS suction following an event involvingcollapse of cooling tower cells CT 2-3 through CT 2-11 has also been evaluated.
The velocity through the suction grating at an ACS flow rate of 8000 gpm is 0.25 ft/sec which is 10% of the velocity required to keep sediment in suspension. This low velocity coupled with the tower cross bracing in two directions will prevent migration of debris to the ACS suction. The RHRSW system takes suction from a pit in the northwest corner of CT 2-1. The pit is approximately 60 feet from the nearest non-Seismic Class I cell. The suction pit is covered by steel grating.
During alternate cooling system operation, RHRSW system flow is recirculated through CT 2-1. The only flow into CT 2-1 from the basin below the remaining cells is the flow required to make up for normal operating losses, such as, evaporation and drift. The flow rate from adjacent cells into CT 2-1 is low with a resulting velocity of less than a tenth of the 0.25 ft/sec velocity .... for flow through the grating over the suction pit. Failure of cooling tower cells CT 2-3 through CT 2-11 (9 of 11 cells) andassociated components has no impact on safety-related cooling tower cell CT 2-
 
1.Subpar t II: As identified in the VYNPS LRA, the aging effects on the cooling tower woodenstructures are: (a)change in material properties, (b)cracking, and (c)loss of material. The aging mechanisms associated with the partial failure of CT 2-4 are: (a)iron salt attack (formation of iron salts in the wood where ferroushardware contacts the lumber and degrades the wood cells),
2-155(b)fungal attack (wood destroying microscopic organism calleddecay fungi that forms in wood exposed to suitable temperature
 
40 oF-140 oF in moist environment), and(c)repeated wetting and drying cycles causing wood checking andphysical damage which reduces wood strength. The circulating water piping within the cooling tower is made of fiberglass and issecured in wooden support saddles. The piping separation event resulted from the distribution deck sag that caused the bell/spigot joint to separate. It did not result from the effects of aging on the fiberglass piping. The wooden saddles supporting the distribution header were found in good condition with no significant degradation. The supporting columns for the circulating water header experienced a reductionin strength due to iron salt attack and fungal attack at the upper spliced joints that caused cracking. This caused the initial failure of several support columns that led to deck sag and separation of the fiberglass circulating water piping joint, thereby increasing the local water loading, causing the additional column failures that lead to the partial failure of CT 2-4. Response to Part C:The circulating water piping separated due to the initial CT 2-4 column failure,rather than due to the effects of aging. This failure does not indicate a need to change the aging management programs for the circulating water piping. Thus, there is no impact on the aging management programs for circulating water piping. Aging effects identified in the VYNPS LRA for the cooling tower structuralelements are; loss of material, cracking and change in material properties.
These aging effects are consistent with those associated with the failure of CT 2-
: 4. The LRA identifies a need for enhancing the Structures Monitoring Program to add guidance for performing examinations of the wood cooling tower elements as appropriate to identify a loss of material, cracking, or change in material properties. This enhancement will include details for the examination and acceptance criteria for wood structures and structural components (i.e., columns and circulating water pipe supports) to ensure aging effects are identified and corrected prior to a loss of intended function. To detect a change in material properties, the enhancement will entail inspections that are more involved than remote visual surface inspections. Lessons learned from review of the failure of CT 2-4 will be considered in implementation of the enhancement identified for the Structures Monitoring Program. The staff determined that the applicant has appropriately included cooling tower cells CT 2-1and CT 2-2 within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(1) and (a)(2), respectively, and has committed (Commitment #21) to enhance and apply the Structures Monitoring Program to the cooling towers. In addition, the applicant has articulated the significant  differences in design, material specifications, level of quality 2-156assurance oversight and maintenance between cooling tower cells CT 2-1 through CT 2-2 andthose of cooling tower cell CT 2-3 through CT 2-11. These features, along with the execution of the Structures Monitoring Program, would preclude cooling tower cells CT 2-1 and CT 2-2 from failing in the manner of cooling tower cell CT 2-4. The additional information provided by the applicant demonstrated that cooling tower cells CT 2-3 through CT 2-11 do not meet the criteria of 10 CFR 54.4(a) for inclusion within the scope of license renewal in that they do not perform an intended function as defined by 10 CFR 54.4(a)(1) or (a)(3). Also, with the aid of the "breakaway" connections design, their failure would not prevent a safety-related SSC from performing its intended function as defined by 10 CFR 54.4(a)(2). Based on a review of the additional information provided by the applicant, the staff finds the applicant's response to RAI 2.4.4-2 acceptable.2.4.4.3  ConclusionThe staff reviewed the LRA and related structural components to determine whether theapplicant failed to identify any SSCs within the scope of license renewal or subject to an AMR.
The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the process facilities components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.5  Yard Structures 2.4.5.1  Summary of Technical Information in the ApplicationLRA Section 2.4.5 describes the yard structures, structures not contained within the primarycontainment, reactor building, intake structure, or process facilities. Yard structures include the condensate storage tank foundation and enclosure structure, FO storage tank foundation and transfer pump house, N 2 storage tank foundation and enclosure, low-pressure CO 2 tankfoundation and enclosure, JDD building, startup transformer foundation, switchyard relay house, trenches, manholes, duct banks, Vernon tie transformer foundation, Vernon Dam and hydroelectric station, and transmission towers. The condensate storage tank is near the southeast corner of the turbine building. The carbon steel enclosure houses safety-related equipment of the CST system. The FO storage tank holds make-up fuel for the EDG day tanks.
A FO transfer pump house contains the FO pumps. The liquid N 2 storage tank enclosure is aseismic Class I structure designed so no instantaneous introduction of a high concentration of
 
N 2 gas into the DG air intake occurs if the storage tank fails. A restraining wall around the baseof the tank collects liquid N 2 and minimizes surface area to limit the boil-off rate of spilled N 2.The tank, located adjacent to the east side of the reactor building, is supported by a reinforced concrete foundation and structural steel support columns to meet seismic design requirements.
The reinforced concrete CO 2 tank (TK-115-1) foundation is adjacent to the northeast corner ofthe switchgear room. A metal enclosure houses and protects electrical and mechanical equipment for the tank against the environment. The JDD powers emergency lighting credited for alternate shutdown in the safe shutdowncapability analysis. The start-up transformers (T-3A & B) on the west side of the turbine building are supported by reinforced concrete pedestals raised above a crushed rock bed. The startup transformers provide power during recovery from SBO. The switchyard control house, also 2-157known as the switchyard relay house, a single-story structure in the main switchyard, housesrelays that control the offsite 115 kV lines. The trenches, manholes and duct banks throughout the VYNPS site, support and protect plant equipment. Those that support or protect equipment within the scope of license renewal are also in-scope. Duct banks route electrical cables between buildings and in the switchyard area. The Vernon tie transformer is on a reinforced concrete slab located approximately 50 feetnorthwest of the west cooling tower and formed on a gravel and sand base to minimize frost heaving. The Vernon tie transformer is credited for SBO. Vernon Dam on the Connecticut River is constructed of concrete and steel and used for hydro-electric generation as an alternate source of AC power in an SBO. The dam and powerhouse are founded on compact rock and the power block superstructure is comprised of reinforced concrete, masonry brick, and structural steel. The dam is not a site structure owned by the applicant. Transmission towers are constructed of galvanized steel reinforced concrete foundations. In-scope towers are the 115 kV tower in the 115 kV switchyard, the 115KV angle tower located west of the turbine building, and the 115/345 kV shared tower in the 345 kV switchyard.The yard structures have safety-related components relied upon to remain functional during andfollowing DBEs. The failure of nonsafety-related yard structure SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the yard structures perform functions that support fire protection and SBO.LRA Table 2.4-5 identifies the following yard structures component types within the scope oflicense renewal and subject to an AMR:
* steel and other metals
* concreteThe yard structures component intended functions within the scope of license renewal includethe following:
* shelter or protection to safety-related equipment, including radiation shielding and pipewhip restraint
* protective barrier for flood events
* missile barrier
* structural or functional support to nonsafety-related equipment the failure of which couldimpact safety-related equipment
* structural or functional support for equipment required to meet fire protection,environmental qualification, PTS, ATWS, or SBO regulations
* structural or functional support for safety-related equipment2.4.5.2  Staff EvaluationThe staff reviewed LRA Section 2.4.5 using the evaluation methodology described in SERSection 2.4 and the guidance in SRP-LR Section 2.4.
2-158The staff evaluated the structural component functions described in the LRA and UFSAR toverify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).In RAI 2.4.5-1 dated August 3, 2006, the staff stated that Table 2.4.5 lists "Vernon Damexternal walls above/below grade" as a component, and "Vernon Dam external walls, floor slabs and interior walls" as another component. The staff requested that the applicant provide clarification for the two different components.In its response dated September 5, 2006, the applicant provided the following response: In Table 2.4.5, item "Vernon Dam external walls above/below grade" refers to theoutside surface of the exterior walls and the second line item "Vernon Dam external walls, floor slabs and interior walls" refers to the interior surface of the exterior walls along with floors and interior walls. This distinction is consistent with the treatment of each of these as having separate environments as shown in Table 3.5.2-5. Based on its review, the staff finds the applicant's response to RAI 2.4.5-1 acceptable becauseit distinguishes the exterior surface of the Vernon Dam wall from the interior surface of the wall, which are subjected to different environments. The staff's concern described in RAI 2.4.5-1 is resolved.2.4.5.3  ConclusionThe staff reviewed the LRA and related structural components to determine whether theapplicant failed to identify any SSCs within the scope of license renewal or subject to an AMR.
The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the yard structures components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.6  Bulk Commodities 2.4.6.1  Summary of Technical Information in the ApplicationLRA Section 2.4.6 describes the bulk commodities, structural components or commodities thatperform or support intended functions of in-scope SSCs. Bulk commodities unique to specific structures are included in the reviews for those structures (SER Sections 2.4.1 through 2.4.5).
This section addresses bulk commodities common to in-scope SSCs (e.g., anchors, embedments, pipe and equipment supports, instrument panels and racks, cable trays, and conduits).The bulk commodities have safety-related components relied upon to remain functional duringand following DBEs. The failure of nonsafety-related bulk commodity SSCs potentially could 2-159prevent the satisfactory accomplishment of a safety-related function. In addition, the bulkcommodities perform functions that support fire protection, ATWS, SBO, and environmental qualification.LRA Table 2.4-6 identifies the following bulk commodity component types within the scope oflicense renewal and subject to an AMR:
* steel and other metals
* concrete
* elastomers and other materials
* fluoropolymers and lubrite sliding surfacesThe bulk commodity component intended functions within the scope of license renewal includethe following:
* shelter or protection to safety-related equipment, including radiation shielding and pipewhip restraint
* rated fire barrier to confine or retard a fire from spreading
* protective barrier for flood events
* insulation
* missile barrier
* pressure boundary
* structural or functional support to nonsafety-related equipment the failure of which couldimpact safety-related equipment
* structural or functional support for equipment required to meet fire protection,Environmental qualification, PTS, ATWS, or SBO regulations
* structural or functional support for safety-related equipment2.4.6.2  Staff EvaluationThe staff reviewed LRA Section 2.4.6 using the evaluation methodology described in SERSection 2.4 and the guidance in SRP-LR Section 2.4.The staff evaluated the structural component functions described in the LRA and UFSAR toverify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1).In RAI 2.4.6-1 dated August 3, 2006, the staff stated that Table 2.4.6 lists "Flood curbs" as acomponent with intended functions for flood barrier and shelter or protection, and another component "Flood curbs" with an intended function for flood barrier. The staff requested that the applicant provide clarification for the two different components.
2-160In its response dated September 5, 2006, the applicant provided the following response: For VYNPS, flood curbs constructed of either concrete or steel perform the sameintended function, which is to provide shelter or protection by serving as flood barriers. In essence, flood barrier and shelter or protection are the same function and both entries for flood curbs fulfill the same function. Based on its review, the staff finds the applicant's response to RAI 2.4.6-1 acceptable becausethe applicant explained that the two entries for flood curbs perform the same intended function.
The staff's concern described in RAI 2.4.6-1 is resolved.2.4.6.3  ConclusionThe staff reviewed the LRA and related structural components to determine whether theapplicant failed to identify any SSCs within the scope of license renewal or subject to an AMR.
The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the bulk commodities components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.5  Scoping and Screening Results: Elect rical and Instrumentation and ControlSystemsThis section documents the staff's review of the applicant's scoping and screening results forelectrical and instrumentation and control (EIC) systems.In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive,long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff's review focused on the implementation results. This focus allowed the staff to confirm that there were no omissions of EIC system components that meet the scoping criteria and subject to an AMR.The staff's evaluation of the information in the LRA was the same for all EIC systems. Theobjective was to determine whether the applicant has identified, as required by 10 CFR 54.4, components and supporting structures for EIC systems that appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant's screening results to verify that all passive, long-lived components were subject to an AMR as required by 10 CFR 54.21(a)(1).In its scoping evaluation, the staff reviewed the applicable LRA sections and componentdrawings, focusing on components that have not been identified as within the scope of license renewal. The staff reviewed relevant licensing basis documents, including the UFSAR, for each EIC system to determine whether the applicant has omitted from the scope of license renewal components with intended functions as required by 10 CFR 54.4(a). The staff also reviewed the licensing basis documents to determine whether the LRA specified all intended functions asrequired by 10 CFR 54.4(a). The staff requested additional information to resolve any omissions or discrepancies identified.
2-161Once the staff completed its review of the scoping results, the staff evaluated the applicant'sscreening results. For those SCs with intended functions, the staff sought to determine: (1) if the functions are performed with moving parts or a change in configuration or properties, or (2) if they are subject to replacement based on a qualified life or specified time period, as required by 10 CFR 54.21(a)(1). For those that did not meet either of these criteria, the staff sought to confirm that these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1).
If discrepancies were identified, the staff requested additional information to resolve them.2.5.1  Summary of Technical Information in the ApplicationLRA Section 2.5 describes the EIC systems. Plant EIC systems are included within the scope oflicense renewal as are EIC components in mechanical systems. The default inclusion of plant EIC systems within the scope of license renewal reflects the method for IPAs of electrical systems. This method differs from those used for IPAs of mechanical systems and structures.VYNPS electrical commodity groups correspond to two of the commodity groups identified inNEI 95-10: (1) high-voltage insulators and (2) cables and connections, busses, and electrical portions of EIC penetration assemblies. The IPA eliminated commodity groups and specific plant systems from further review as the intended functions of commodity groups were examined. In addition to the plant electrical systems, certain switchyard components required to restore offsite power following a SBO were conservatively included within the scope of license renewal although they are not relied on in safety analyses or plant evaluations to perform functions for compliance with SBO regulations. The offsite power system provides the electrical interconnection between the generator and the offsite transmission network and between the offsite network and the auxiliary buses as well as other buildings and facilities.The EIC systems perform functions that support SBO.
LRA Table 2.5-1 identifies the following EIC systems component types within the scope oflicense renewal and subject to an AMR:
* cable connections (metallic parts)
* electrical cables, connections, and fuse holders (insulation) not subject to 10 CFR 50.49Environmental qualification requirements
* electrical cables not subject to 10 CFR 50.49 Environmental qualification requirementsused in instrumentation circuits
* fuse holders (insulation material)
* high-voltage insulators
* inaccessible medium-voltage (4.16 kV to 22 kV) cables (e.g., installed underground inconduit or direct buried) not subject to 10 CFR 50.49 Environmental qualification requirements
* switchyard bus
* transmission conductors 2-162The EIC systems component intended functions within the scope of license renewal include thefollowing:
* provide electrical connections to specified sections of an electrical circuit to delivervoltage, current, or signals
* insulate and support electrical conductor2.5.2  Staff EvaluationThe staff reviewed LRA Section 2.5 and UFSAR Sections 7 and 8 using the evaluationmethodology described in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5, "Scoping and Screening Results: Electrical andInstrumentation and Controls Systems." The staff reviewed the scoping methodology of the applicant, and considered it to be acceptable in accordance with the "Plant Spaces" approach method in NUREG-1800, Revision 1, Table 2.5.1. This approach eliminates the need for unique identification of every component and its specific location. This assures components are not excluded from an AMR.As documented in SER, Section 3.6.2.3.1, the staff determined that uninsulated groundconductors are not in the scope of licence renewal and do not require an AMR.In RAI 2.5-1, the staff requested the applicant to provide brief descriptions of the systems, listedin LRA Table 2.2-1b, explaining how each system serves one or more functions listed in 10 CFR 54.4(a).In its response dated September 5, 2006, the applicant stated that: As described in LRA Section 2.5, all plant electrical and Instrumentation andControl (EIC) systems are included in the scope of license renewal. EIC equipment in mechanical systems is included in the scope of license renewal, regardless of whether the mechanical system is included in-scope. Including components beyond those actually required is referred to as an encompassing review. This method eliminates the need for unique identification of each system and its specific function. This assures components are not improperly excluded from the scope of license renewal.Based on its review, the staff finds the above response to the RAI 2.5-1 acceptable becausewhen used with "Plant Spaces"approach, this method eliminates the need for unique identification of each system and its specific function. The staff's concern described in RAI 2.5-1 is resolved.In RAI 2.5-2, the staff requested the applicant to provide details of Vermont Yankee NuclearPower Station's alternate alternating current (AAC) source, and also describe the offsite power recovery paths from switchyard to the onsite distribution which are in the license renewal scope to satisfy the requirements of 10 CFR 50.63. In its response dated September 5, 2006, the applicant stated that:
2-163The parts of the AAC that are subject to AMR are explained in the response toRAI 3.6.2.2-N-08. The offsite power recovery paths from switchyard to the onsite distribution system which are in the license renewal scope are the source fed through the start-up transformers and a delayed access circuit from the 345 kV switchyard through the main and auxiliary transformers via the isophase bus.
Specifically, the start-up transformer path includes; the 115 kV switchyard circuit breaker feeding the start-up transformers, the start-up transformers, the circuit breaker-to-transformers and transformer-to-onsite electrical distribution interconnections, and the associated control circuits and structures. The delayed access circuit is made available by opening the generator no-load disconnectswitch and establishing a feed from the 345kV switchyard through the main and auxiliary transformers via the isophase bus.The staff reviewed the applicant response to RAI 3.6.2.2-N-08, provided in the letter datedJuly 14, 2006, in which it stated that the VHS is the AAC source credited for Vermont Yankee Nuclear Power Station (VYNPS) to demonstrate compliance with 10 CFR 50.63, loss of all alternating current power (the station blackout rule). As such, all VHS structures, systems, and components (SSCs) are in the scope of license renewal. Based on its review of the response to RAI 3.6.2.2-N-08, and further clarifications provided bythe applicant in its letter dated January 4, 2007, Attachment 4, the staff finds the applicant's response to RAI 2.5-2 acceptable because the applicant has included all necessary components of the AAC source in the scope of license renewal. The staff's concern described in RAI 2.5-2 is resolved.The applicant initially excluded metal-enclosed bus connections, and bus enclosure assembliesand insulators from the AMR. However, in its response dated September 5, 2006 to the staff's RAI 2.5-3, the applicant clarified that the metal-enclosed isophase bus is now included in the AMR. This isophase bus is part of the delayed access circuit (to support SBO recovery actions) from the 345 kV switchyard through the main generator step-up transformer and unit auxiliary transformer. The applicant stated that the VYNPS Metal Enclosed Bus Program will manage the effects of aging of the isophase bus and will be consistent with the GALL Report aging management program X1.E4 (NUREG-1801, Volume 2, Rev 1).Based on above response provided by the applicant in its letter dated September 5, 2006, thestaff considers that the applicant has included necessary components of the metal-enclosed bus connections, bus enclosure assemblies and insulators subject to an AMR. The RAI 2.5-3 response is considered acceptable. The staff's concern described in RAI 2.5-3 is resolved.In RAI 2.5-4, the staff asked the applicant to provide justification, in detail, why the cableconnections (metallic portion) was not included in the scope of an AMR although the GALL Report aging management program XI.E6, "Electrical Cable Connections not Subject to 10 CFR 50.49 Environmental Qualification Requirements," recommended such an aging managing program.In its letter dated September 5, 2006, the licensee provided the following justification:
2-164Metallic parts of electrical cable connections that are exposed to thermal cyclingand ohmic heating are those carrying significant current in power supply circuits.
VYNPS power cables are in a continuous run from the supply to the load. The connections to the supply and to the load are parts of active components that are not subject to aging management review in accordance with 10 CFR 54.21. As discussed in the statement of considerations for the license renewal rule, maintenance rule activities are credited with managing the effects of aging on active components.
The fast action of circuit protective devices at high currents mitigates stresses associated with electrical faults and transients. In addition, mechanical stressassociated with electrical faults is not a credible aging mechanism because ofthe low frequency of occurrence for electrical faults. Therefore, electrical transients are not aging mechanisms.Metallic parts of electrical cable connections exposed to vibration are thoseassociated with active components that cause vibration. Active components are not subject to aging management review in accordance with 10 CFR 54.21. As discussed in the statement of considerations for the license renewal rule, maintenance rule activities are credited with managing the effects of aging on active components.
Corrosive chemicals are not stored in most areas of the plant. Routine releases of corrosive chemicals to areas inside plant buildings do not occur during plant operation and corrosive chemicals are not a normal environment for electrical connections. Contamination of electrical connections causes rapid degradationindependent of the age of the connection components. Corrosion due to contamination is due to the contamination event rather than aging. Therefore, chemical contamination is not an aging mechanism for electrical connections. Corrosion and oxidation occur in the presence of moisture or contamination suchas industrial pollutants and salt deposits. Enclosures and splice materials protect metal connections from moisture and contamination. Therefore, oxidation and corrosion are not applicable aging mechanisms.Electrical cable connections at VYNPS are inspected in accordance with themaintenance rule program as directed by plant procedures. The maintenance rule program, based on industry guidance provided in NUMARC 93-01 and Reg.
Guide 1.160, complies with 10 CFR 50.65. The maintenance rule program includes performance monitoring and trending. Monitoring and trending includes normal plant maintenance activities. Maintenance includes activities associated with identifying and correcting actual or potential degraded conditions (e.g.,
repair, surveillance, diagnostic examinations, and preventive measures).Thermography is used to detect potential degraded conditions. Thermography candetect "hot spots" in cable connections that are indicative of a high resistance connection.As a part of the maintenance rule program, periodic assessments are performed.A periodic assessment is performed to evaluate the effectiveness of 2-165maintenance activities. This assessment is performed at least every operatingcycle, not to exceed 24 months. Plant operating experience has shown that the maintenance rule program has been effective at detecting, evaluating and repairing electrical cable connection degradation.The maintenance rule program includes scoping, performance monitoring,trending and periodic assessments. This program provides reasonable assurance that electrical cable connections will remain capable of performing their intended functions through the period of extended operation. No aging management program (AMP) for license renewal is required at VYNPS since the regulatory mandated maintenance rule program effectively maintains electrical cable connections.Subsequent to above response, on November 30, 2006, NEI held a meeting with NRC. Basedon this meeting, XI.E6 program was revised to be a one-time inspection of a representative sample of cable connections subject to aging management review. In its letter dated January 4, 2007, Attachment 7, the applicant agreed to a plant-specific Bolted Cable Connection Program.Based on licensee agreement to implement a Bolted Cable Connection Program as detailed inits letter dated January 4, 2007, the staff considers the issue raised in RAI 2.5-4 resolved.2.5.3  ConclusionThe staff reviewed the LRA Section 2.5, the UFSAR, and the supplemental informationprovided by the applicant in its letters dated September 5, 2006, and January 4, 2007, to determine whether any SSCs that should be within the scope of license renewal or subject to an AMR had not been identified by the applicant. No omissions were identified. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant had adequately identified the electrical commodity group components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.6  Conclusion for Scoping and ScreeningThe staff reviewed the information in LRA Section 2, "Scoping and Screening Methodology for Identifying Structures and Components Subject to Aging Management Review and Implementation Results," and determines that the applicant's scoping and screening methodology was consistent with the requirements of 10 CFR 54.21(a)(1) and the staff's positions on the treatment of safety-related and nonsafety-related SSCs within the scope of license renewal and on SCs subject to an AMR is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1).On the basis of its review, the staff concludes, pending resolution of ConfirmatoryItems 2.3.3.2a-1, 2.3.3.2a-2, 2.3.3.12-1, 2.3.3.13a-1, 2.3.3.13e-1, and 2.3.3.13m-1, that the applicant has adequately identified those systems and components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-166The staff concludes that there is reasonable assurance that the applicant will continue toconduct the activities authorized by the renewed license in accordance with the CLB and any changes to the CLB in order to comply with 10 CFR 54.21(a)(1), in accordance with the Atomic Energy Act of 1954, as amended, and NRC regulations.
3-1 SECTION  3AGING MANAGEMENT REVIEW RESULTSThis section of the safety evaluation report (SER) evaluates aging management programs(AMPs) and aging management reviews (AMRs) for Vermont Yankee Nuclear Power Station (VYNPS), by the staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff). In Appendix B of its license renewal application (LRA), Entergy Nuclear Operations, Inc.
(ENO or the applicant) described the 36 AMPs that it relies on to manage or monitor the aging of passive, long-lived structures and components (SCs).In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified inLRA Section 2 as within the scope of license renewal and subject to an AMR.3.0  Applicant's Use of the Generic Aging Lessons Learned ReportIn preparing its LRA, the applicant credited US NRC NUREG-1801, Volume 2, Revision 1, "Generic Aging Lessons Learned (GALL) Report," dated September 2005. The GALL Report contains the staff's generic evaluation of the existing plant programs and documents the technical basis for determining where existing programs are adequate without modification, and where existing programs should be augmented for the period of extended operation. The evaluation results documented in the GALL Report indicate that many of the existing programs are adequate to manage the aging effects for particular license renewal SCs. The GALL Report also contains recommendations on specific areas for which existing programs should be augmented for license renewal. An applicant may reference the GALL Report in its LRA to demonstrate that its programs correspond to those reviewed and approved in the report.The purpose of the GALL Report is to provide a summary of staff-approved AMPs to manage ormonitor the aging of SCs subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and resources for LRA review will be greatly reduced, improving the efficiency and effectiveness of the license renewal review process. The GALL Report also serves as a quick reference for applicants and staff reviewers to AMPs and activities that the staff determines will adequately manage or monitor aging during the period of extended operation.The GALL Report identifies: (1) systems, structures, and components (SSCs), (2) SC materials,(3) environments to which the SCs are exposed, (4) the aging effects of the materials and environments, (5) the AMPs credited with managing or monitoring the aging effects, and (6) recommendations for further applicant evaluations of aging management for certain component types.To determine whether use of the GALL Report would improve the efficiency of LRA review, thestaff conducted a demonstration of the GALL Report process in order to model the format and content of safety evaluations (SEs) based on it. The results of the demonstration project confirmed that the GALL Report process will improve the efficiency and effectiveness of LRA review, while maintaining the staff's focus on public health and safety. NUREG-1800, 3-2Revision 1, "Standard Review Plan for Review of License Renewal Applications for NuclearPower Plants" (SRP-LR), dated September 2005, was prepared based on both the GALL Report model and lessons learned from the demonstration project.The staff's review was in accordance with Title 10, Part 54, of the Code of Federal Regulations(10 CFR 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants," and the guidance of the SRP-LR and the GALL Report.In addition to its review of the LRA, the staff conducted an onsite audit of selected AMRs andassociated AMPs, during the weeks of April 17-21, 2006, May 15-19, 2006 and June 26-28, 2006. The staff documented the results of its audit and review in "Audit and Review Report for Plant Aging Management Reviews and Programs, Vermont Yankee Nuclear Power Station" (Audit and Review Report). The onsite audits and reviews are designed for maximum efficiency of the staff's LRA review. The applicant can respond to questions, the staff can readily evaluate the applicant's responses, and the need for formal correspondence between the staff and the applicant is reduced, resulting in an improvement in review efficiency.3.0.1  Format of the License Renewal ApplicationThe applicant submitted an application that follows the standard LRA format agreed to by thestaff and the Nuclear Energy Institute (NEI) agreed by letter dated April 7, 2003 (ML030990052). This revised LRA format incorporates lessons learned from the staff's reviews of the previous five LRAs, which used a format developed from information gained during a staff-NEI demonstration project conducted to evaluate the use of the GALL Report in the LRA review process.The organization of LRA Section 3 parallels that of SRP-LR Chapter 3. LRA Section 3 presentsAMR results information in the following two table types:  (1)Table 1s: Table 3.x.1 - where "3" indicates the LRA Section number, "x" indicates thesubsection number from the GALL Report, and "1" indicates that this table type is the first in LRA Section 3.  (2)Table 2s: Table 3.x.2-y - where "3" indicates the LRA Section number, "x" indicates thesubsection number from the GALL Report, "2" indicates that this table type is the second in LRA Section 3, and "y" indicates the system table number.The content of the previous LRAs and of the VYNPS application is essentially the same. Theintent of the revised format of the LRA was to modify the tables in LRA Section 3 to provide additional information that would assist in the staff's review. In its Table 1s, the applicant summarized the portions of the application that it considered to be consistent with the GALL Report. In its Table 2s, the applicant identified the linkage between the scoping and screening results in LRA Section 2 and the AMRs in LRA Section 3.
3-33.0.1.1  Overview of Table 1sEach Table 1 compares in summary how the facility aligns with the corresponding tables in theGALL Report. The tables are essentially the same as Tables 1 through 6 in the GALL Report, except that the "Type" column has been replaced by an "Item Number" column and the "Item Number in GALL" column has been replaced by a "Discussion" column. The "Item Number" column is a means for the staff reviewer to cross-reference Table 2s with Table 1s. In the "Discussion" column the applicant provided clarifying information. The following are examples of information that might be contained within this column:
* further evaluation recommended - information or reference to where that information is located
* The name of a plant-specific program
* exceptions to GALL Report assumptions
* discussion of how the line is consistent with the corresponding line item in the GALLReport when the consistency may not be obvious
* discussion of how the item is different from the corresponding line item in the GALLReport (e.g., when an exception is taken to a GALL AMP)The format of each Table 1 allows the staff to align a specific row in the table with thecorresponding GALL Report table row so that the consistency can be checked easily.3.0.1.2  Overview of Table 2sEach Table 2 provides the detailed results of the AMRs for components identified in LRASection 2 as subject to an AMR. The LRA has a Table 2 for each of the systems or structures within a specific system grouping (e.g., reactor coolant systems, engineered safety features (ESF), auxiliary systems, etc.). For example, the ESF group has tables specific to the core spray system (CSS), high pressure coolant injection system (HPCIS), and residual heatremoval system (RHRS). Each Table 2 consists of nine columns:  (1)Component Type - The first column lists LRA Section 2 component types subject to anAMR in alphabetical order.  (2)Intended Function - The second column identifies the license renewal intendedfunctions, including abbreviations, where applicable, for the listed component types.
Definitions and abbreviations of intended functions are in LRA Table 2.0-1.  (3)Material - The third column lists the particular construction material(s) for thecomponent type.  (4)Environment - The fourth column lists the environments to which the component typesare exposed. Internal and external service environments are indicated with a list of these environments in LRA Tables 3.0-1, 3.0-2, and 3.0-3.  (5)Aging Effect Requiring Management - The fifth column lists aging effects requiringmanagement (AERM). As part of the AMR process, the applicant determined any AERMs for each combination of material and environment.
3-4  (6)Aging Management Programs - The sixth column lists the AMPs that the applicant usesto manage the identified aging effects.  (7)NUREG-1801 Volume 2 Item - The seventh column lists the GALL Report item(s)identified in the LRA as similar to the AMR results. The applicant compares each combination of component type, material, environment, AERM, and AMP in LRA Table 2 with the GALL Report items. If there are no corresponding items in the GALL Report, the applicant leaves the column blank in order to identify the AMR results in the LRA tables corresponding to the items in the GALL Report tables.  (8)Table 1 Item - The eighth column lists the corresponding summary item number fromLRA Table 1. If the applicant identifies in each LRA Table 2 AMR results consistent with the GALL Report, the associated Table 1 line item summary number should be listed in LRA Table 2. If there is no corresponding item in the GALL Report, column eight is left blank. In this manner, the information from the two tables can be correlated.  (9)Notes - The ninth column lists the corresponding notes used to identify how theinformation in each Table 2 aligns with the information in the GALL Report. The notes, identified by letters, were developed by an NEI work group and will be used in future LRAs. Any plant-specific notes identified by numbers provide additional information about the consistency of the line item with the GALL Report.3.0.2  Staff's Review ProcessThe staff conducted three types of evaluations of the AMRs and AMPs:  (1)For items that the applicant stated were consistent with the GALL Report the staffconducted either an audit or a technical review to determine such consistency.  (2)For items that the applicant stated were consistent with the GALL Report withexceptions, enhancements, or both, the staff conducted either an audit or a technical review of the item to determine such consistency. In addition, the staff conducted either an audit or a technical review of the applicant's technical justifications for the exceptions or the adequacy of the enhancements.The SRP-LR states that an applicant may take one or more exceptions to specific GALLAMP elements; however, any deviation from or exception to the GALL AMP should be described and justified. Therefore, the staff considers exceptions as being portions of the GALL AMP that the applicant does not intend to implement.In some cases, an applicant may choose an existing plant program that does not meetall the program elements defined in the GALL AMP. However, the applicant may make a commitment to augment the existing program to satisfy the GALL AMP prior to the period of extended operation. Therefore, the staff considers these augmentations or additions to be enhancements. Enhancements include, but are not limited to, activities needed to ensure consistency with the GALL Report recommendations. Enhancements may expand, but not reduce, the scope of an AMP.  (3)For other items, the staff conducted a technical review to verify conformance with10 CFR 54.21(a)(3) requirements.
3-5Staff audits and technical reviews of the applicant's AMPs and AMRs determine whether theeffects of aging on SCs can be adequately managed to maintain their intended function(s) consistent with the plant's current licensing basis (CLB) for the period of extended operation, as required by 10 CFR Part 54.3.0.2.1  Review of AMPsFor AMPs for which the applicant claimed consistency with the GALL AMPs, the staff conductedeither an audit or a technical review to verify the claim. For each AMP with one or more deviations, the staff evaluated each deviation to determine whether the deviation was acceptable and whether the modified AMP would adequately manage the aging effect(s) for which it was credited. For AMPs not evaluated in the GALL Report, the staff performed a full review to determine their adequacy. The staff evaluated the AMPs against the following 10 program elements defined in SRP-LR Appendix A.  (1)Scope of the Program - Scope of the program should include the specific SCs subjectto an AMR for license renewal.  (2)Preventive Actions - Preventive actions should prevent or mitigate aging degradation.
  (3)Parameters Monitored or Inspected - Parameters monitored or inspected should belinked to the degradation of the particular structure or component intended function(s).  (4)Detection of Aging Effects - Detection of aging effects should occur before there is aloss of structure or component intended function(s). This includes aspects such as method or technique (i.e., visual, volumetric, surface inspection), frequency, sample size, data collection, and timing of new/one-time inspections to ensure timely detection of aging effects.  (5)Monitoring and Trending - Monitoring and trending should provide predictability of theextent of degradation, as well as timely corrective or mitigative actions.  (6)Acceptance Criteria - Acceptance criteria, against which the need for corrective actionwill be evaluated, should ensure that the structure or component intended function(s) are maintained in accordance with all CLB design conditions during the period of extended operation.  (7)Corrective Actions - Corrective actions, including root cause determination andprevention of recurrence, should be timely.  (8)Confirmation Process - Confirmation process should ensure that preventive actions areadequate and that appropriate corrective actions have been completed and are effective.  (9)Administrative Controls - Administrative controls should provide for a formal review andapproval process.  (10)Operating Experience - Operating experience of the AMP, including past correctiveactions resulting in program enhancements or additional programs, should provide objective evidence to support the conclusion that the effects of aging will be adequately managed so that the SC intended function(s) will be maintained during the period of extended operation.
3-6Details of the staff's audit evaluation of program elements (1) through (6) are documented inSER Section 3.0.3.The staff reviewed the applicant's quality assurance (QA) program and documented itsevaluations in SER Section 3.0.4. The staff's evaluation of the QA program included assessment of the "corrective actions," "confirmation process," and "administrative controls" program elements.The staff reviewed the information on the "operating experience" program element anddocumented its evaluation in SER Section 3.0.3.The staff reviewed the Updated Final Safety Analysis Report (UFSAR) Supplement for eachAMP to determine if it provided an adequate description of the program or activity, as required by 10 CFR 54.21(d).3.0.2.2  Review of AMR ResultsEach LRA Table 2 contains information concerning whether or not the AMRs identified by theapplicant align with the GALL Report AMRs. For a given AMR in a Table 2, the staff reviewed the intended function, material, environment, AERM, and AMP combination for a particular system component type. Item numbers in LRA column seven, "GALL Report Volume 2 Item,"
correlates to an AMR combination as identified in the GALL Report. The staff also conducted onsite audits to verify these correlations. A blank in column seven indicates that the applicant was unable to identify an appropriate correlation in the GALL Report. The staff also conducted a technical review of combinations not consistent with the GALL Report. The next column, "Table 1 Item," refers to a number indicating the correlating row in Table 1.3.0.2.3  UFSAR SupplementConsistent with the SRP-LR for the AMRs and AMPs that it reviewed, the staff also reviewedthe UFSAR supplement, which summarizes the applicant's programs and activities for managing the effects of aging for the period of extended operation, as required by 10 CFR 54.21(d).3.0.2.4  Documentation and Documents ReviewedIn its review, the staff used the LRA, LRA supplements, the SRP-LR, and the GALL Report.
During the onsite audit, the staff also examined the applicant's justifications to verify that theapplicant's activities and programs will adequately manage the effects of aging on SCs. The staff also conducted detailed discussions and interviews with the applicant's license renewal project personnel and others with technical expertise relevant to aging management.
3-73.0.3  Aging Management ProgramsSER Table 3.0.3-1 presents the AMPs credited by the applicant and described in LRAAppendix B and subsequent LRA supplements. The table also indicates the SSCs that creditthe AMPs and the GALL AMP with which the applicant claimed consistency and shows the SER section in which the staff's evaluation of the program is documented.Table 3.0.3-1  VYNPS Aging Management ProgramsVYNPS AMP(LRA Section)GALL ReportComparisonGALL ReportAMPsLRA Systems or StructuresThat Credit the AMP Staff's SER SectionExisting AMPs Bolting Integrity Program (B.1.31)Consistent with enhancement XI.M18reactor vessel, internals, andreactor coolant system; ESF systems; auxiliary systems; steam and power conversion systems; SC supports 3.0.3.2.19 Buried Piping Inspection Program (B.1.1)Consistent withexceptions and
 
enhancementsXI.M34ESF systems / auxiliarysystems 3.0.3.2.1BWR CRD Return LineNozzle Program (B.1.2)Consistent withexceptionXI.M6reactor vessel, internals, andreactor coolant system 3.0.3.2.2BWR FeedwaterNozzle Program (B.1.3)Consistent withexceptionXI.M5reactor vessel, internals, andreactor coolant system 3.0.3.2.3BWR Penetrations Program (B.1.4)Consistent withexceptionsXI.M8reactor vessel, internals, andreactor coolant system 3.0.3.2.4BWR Stress CorrosionCracking Program (B.1.5)Consistent withexceptionXI.M7reactor vessel, internals, andreactor coolant system 3.0.3.2.5BWR Vessel InsideDiameter Attachment Welds Program (B.1.6)Consistent withexceptionXI.M4reactor vessel, internals, andreactor coolant system 3.0.3.2.6BWR Vessel Internals Program (B.1.7)Consistent withexceptions and
 
enhancementsXI.M9reactor vessel, internals, andreactor coolant system 3.0.3.2.7Containment LeakRate Program (B.1.8)Consistent withexceptionXI.S4ESF systems / SC supports 3.0.3.2.8Diesel Fuel Monitoring Program (B.1.9)Consistent withexceptions and
 
enhancementsXI.M30auxiliary systems 3.0.3.2.9 VYNPS AMP(LRA Section)GALL ReportComparisonGALL ReportAMPsLRA Systems or StructuresThat Credit the AMP Staff's SER Section3-8EnvironmentalQualification of Electric Components Program (B.1.10)ConsistentX.E1electrical and instrumentation and controls 3.0.3.1.1Fatigue Monitoring Program (B.1.11)Consistent withexceptions and
 
enhancementsX.M1reactor vessel, internals, andreactor coolant system / ESF systems / auxiliary systems /
steam and power conversion systems / SC supports 3.0.3.2.10 Fire Protection Program (B.1.12.1)Consistent withexceptions and
 
enhancementsXI.M26auxiliary systems / SC supports 3.0.3.2.11Fire Water System Program (B.1.12.2)Consistent withexception and
 
enhancementsXI.M27auxiliary systems 3.0.3.2.12Flow-AcceleratedCorrosion Program (B.1.13)ConsistentXI.M17reactor vessel, internals, andreactor coolant system / ESF systems / auxiliary systems /
steam and power conversion systems 3.0.3.1.2Containment Inservice Inspection Program (B.1.15.1)Plant-specificNASC supports 3.0.3.3.2Inservice Inspection Program (B.1.15.2)Plant-specificNAreactor vessel, internals, andreactor coolant system / SC
 
supports 3.0.3.3.3Instrument Air Quality Program (B.1.16)Plant-specificNAauxiliary systems 3.0.3.3.4Oil Analysis Program (B.1.20)Consistent withexceptionXI.M39ESF systems / auxiliarysystems 3.0.3.2.13Periodic Surveillanceand Preventive Maintenance Program (B.1.22)Plant-specificNAESF systems / auxiliarysystems / SC supports 3.0.3.3.5Reactor Head Closure Studs Program (B.1.23)ConsistentXI.M3reactor vessel, internals, andreactor coolant system 3.0.3.2.14Reactor VesselSurveillance Program (B.1.24)Consistent with enhancementXI.M31reactor vessel, internals, andreactor coolant system 3.0.3.2.15Service Water Integrity Program (B.1.26)Consistent withexceptions and
 
enhancement.XI.M20ESF systems / auxiliarysystems 3.0.3.2.16 VYNPS AMP(LRA Section)GALL ReportComparisonGALL ReportAMPsLRA Systems or StructuresThat Credit the AMP Staff's SER Section3-9Masonry Wall Program (B.1.27.1)ConsistentXI.S5SC supports 3.0.3.1.8Structures Monitoring Program (B.1.27.2)Consistent with enhancementsXI.S6SC supports 3.0.3.2.17Vernon Dam FERC Inspection (B.1.27.3)Plant-specificNASC supports 3.0.3.3.6System Walkdown Program (B.1.28)ConsistentXI.M36reactor vessel, internals, andreactor coolant system / ESF systems / auxiliary systems /
steam and power conversion systems 3.0.3.1.9Water ChemistryControl - Auxiliary Systems Program (B.1.30.1)Plant-specificNAESF systems / auxiliarysystems 3.0.3.3.7Water ChemistryControl - BWR
 
Program (B.1.30.2)ConsistentXI.M2reactor vessel, internals, andreactor coolant system / ESF systems / auxiliary systems /
steam and power conversion systems / SC supports 3.0.3.1.11Water ChemistryControl - Closed Cooling Water
 
Program (B.1.30.3)Consistent withexceptionXI.M21reactor vessel, internals, andreactor coolant system / ESF systems / auxiliary systems /
steam and power conversion systems 3.0.3.2.18New AMPsHeat ExchangerMonitoring Program (B.1.14)Plant-specificNAESF systems / auxiliarysystems 3.0.3.3.1Non-EnvironmentalQualification
 
Inaccessible Medium-Voltage Cable
 
Program (B.1.17)ConsistentXI.E3electrical and instrumentation and controls 3.0.3.1.3Non-EnvironmentalQualification
 
Instrumentation Circuits Test Review
 
Program (B.1.18)ConsistentXI.E2electrical and instrumentation and controls 3.0.3.1.4 VYNPS AMP(LRA Section)GALL ReportComparisonGALL ReportAMPsLRA Systems or StructuresThat Credit the AMP Staff's SER Section3-10Non-EnvironmentalQualification Insulated Cables and Connections Program (B.1.19)ConsistentXI.E1electrical and instrumentation and controls 3.0.3.1.5One-Time Inspection Program (B.1.21)ConsistentXI.M32XI.M35reactor vessel, internals, andreactor coolant system / ESF systems / auxiliary systems
/steam and power conversion systems 3.0.3.1.6Selective Leaching Program (B.1.25)ConsistentXI.M33ESF systems / auxiliarysystems 3.0.3.1.7Thermal Aging andNeutron Irradiation Embrittlement of Cast
 
Austenitic Stainless
 
Steel Program (B.1.29)ConsistentXI.M13reactor vessel, internals, andreactor coolant system 3.0.3.1.10Metal-Enclosed Bus Inspection Program (B.1.32)Consistent withexceptionsXI.E4electrical and instrumentation and controls 3.0.3.2.20Bolted CableConnections Program (B.1.33)Plant-specificNAelectrical and instrumentation and controls 3.0.3.3.83.0.3.1  AMPs Consistent with the GALL ReportIn LRA Appendix B, the applicant identified the following AMPs as consistent with the GALLReport:
* Environmental Qualification of Electric Components Program
* Flow-Accelerated Corrosion Program
* Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program
* Non-Environmental Qualification Instrumentation Circuits Test Review Program
* Non-Environmental Qualification Insulated Cables and Connections Program
* One-Time Inspection Program
* Selective Leaching Program
* Masonry Wall Program 3-11
* System Walkdown Program
* Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless SteelProgram
* Water Chemistry Control - BWR Program3.0.3.1.1  Environmental Qualification of Electric Components ProgramSummary of Technical Information in the Application. LRA Section B.1.10 describes the existingEnvironmental Qualification of Electric Components Program as consistent with GALL AMP X.E1, "Environmental Qualification of Electric Components." The Environmental Qualification of Electric Components Program manages componentthermal, radiation, and cyclical aging by aging evaluations based on 10 CFR 50.49(f) qualification methods. As required by 10 CFR 50.49, environmental qualification components not qualified for the current license term are refurbished or replaced or their qualifications are extended prior to reaching the aging limits established in the evaluation. Aging evaluations for environmental qualification components are considered time-limited aging analyses (TLAAs) for license renewal.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The Audit and Review Report documents the details of the staff's evaluation of this AMP.The staff noted that the results of electrical equipment in LRA Section 4.4 indicate that theaging effects of the Environmental qualification electrical equipment identified as a TLAA will be managed during the extended period of operation in accordance with 10 CFR 54.21(c)(1)(iii).
However, no information is provided on the attributes of a re-analysis of aging evaluation to extend the qualification life of electrical equipment identified as TLAA. The important attributes of a re-analysis are the analytical methods, the data collection, the reduction methods, the underlying assumptions, the acceptance criteria, and corrective actions. The staff asked the applicant to provide information on these important attributes of re-analysis of an aging evaluation of electrical equipment identified in the TLAA to extend the qualification in accordance with 10 CFR 50.49(e). In its response, the applicant stated that it would supplement VYNPS AMP B.1.10 to include the "Environmental Qualification Component Re-analysis Attributes" specified in GALL AMP X.E1 as follows:Environmental Qualification Component Re-analysis Attributes:The re-analysis of an aging evaluation is normally performed to extend thequalification by reducing excess conservatism incorporated in the prior evaluation. Re-analysis of an aging evaluation to extend the qualification of a component is performed on a routine basis in accordance with 10 CFR 50.49(e) as part of an Environmental Qualification program. While a component life limiting condition may be due to thermal, radiation, or cyclical aging, the vast majority of component aging limits are based on thermal conditions.
Conservatism may exist in aging evaluation parameters, such as the assumed ambient temperature of the component, an unrealistically low activation energy, 3-12or in the application of a component (de-energized versus energized). There-analysis of an aging evaluation is documented according to the station's quality assurance program requirements, which requires verification of assumptions and conclusions. As already noted, important attributes of a re-analysis include analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, and corrective actions (if acceptance criteria are not met). These attributes are discussed below.Analytical Methods: The analytical models used in the re-analysis of an agingevaluation are the same as those previously applied during the prior evaluation.
The Arrhenius methodology is an acceptable model for performing a thermal aging evaluation. The analytical method used for a radiation aging evaluation demonstrates qualification for the total integrated dose (that is, normal radiation dose for the projected installed life plus accident radiation dose). For license renewal, one acceptable method of establishing the 60-year normal radiation dose is to multiply the 40-year normal radiation dose by 1.5 (that is 60 years/40 years). The result is added to the accident radiation dose to obtain the total integrated dose for the component. For cyclical aging, a similar approach may be used. Other methods may be justified on a case-by-case basis.Data Collection and Reduction Methods: Reducing excess conservatism in thecomponent service conditions (for example, temperature, radiation, cycles) used in the prior aging evaluation is the chief method used for a re-analysis.
Temperature data used in an aging evaluation is to be conservative and based on plant design temperatures or on actual plant temperature data. When used, plant temperature data can be obtained in several ways, including monitors used for technical specification compliance, other installed monitors, measurement made by plant operators during rounds, and temperature sensors on large motors (while the motor is not running). A representative number of temperature measurement are conservatively evaluated to establish the temperatures used in an aging evaluation. Plant temperature data may be used in an aging evaluation in different ways, such as (a) directly applying the plant temperature data in the evaluation, or (b) using the plant temperature data to demonstrate conservatism when using plant design temperature for an evaluation. Any changes to material activation energy values as part of a re-analysis are to be justified on a plant-specific basis. Similar methods of reducing excess conservatism in the component service conditions used in prior aging evaluation can be used for radiation and cyclical aging.Underlying Assumption: Environmental qualification component aging evaluationcontain sufficient conservatism to account for most environmental changes occurring due to plant modifications and events. When unexpected adverse conditions are identified during operational or maintenance activities that affect the normal operating environment of a qualified component, the affected environmental qualification component is evaluated and appropriate corrective actions are taken, which may include changes to the qualification bases and
 
conclusions.
3-13Acceptance Criteria and Corrective Actions: The re-analysis of an agingevaluation could extend the qualification of the component. If the qualification cannot be extended by re-analysis, the component is to be refurbished, replaced, or re-qualified prior to exceeding the period for which the current qualification remains valid. A re-analysis is to be performed in a timely manner (that is, sufficient time is available to refurbish, replace, or re-qualify the component if the re-analysis is unsuccessful.The staff finds the applicant's response acceptable because a re-analysis of the attributes,which is consistent with the attribute recommended in the GALL Report. In a letter dated January 4, 2007, the applicant revised VYNPS AMP B.1.10 to include the "Environmental Qualification Component Re-Analysis Attributes" as described above.The staff also asked the applicant to address how it will analyze and evaluate the equipment inthe Environmental Qualification of Electric Components Program for 60 years per 10 CFR 54.21. The staff asked the applicant to address in its response whether the environmental conditions (both ambient and accident) resulting from the extended power uprate (EPU) will be used as the basis for the analysis and evaluation going forward. In addition, the staff asked the applicant to confirm that the approach described in the response to this question is consistent with its LRA. In its response, the applicant stated that VYNPS willcontinue to use the analysis and evaluation techniques described in 10 CFR 50.49 and Institute of Electrical and Electronics Engineers (IEEE) 323 during the renewal period. The equipment in the Environmental Qualification of Electric Components Program is both active and passive.
The equipment in the Environmental Qualification of Electric Components Program documentation has recently been updated to reflect the normal and accident environments in accordance with EPU conditions. The program considers equipment degradation from EPU radiation dose, normal and accident (loss of coolant accident (LOCA), high energy line break) temperatures as well as cycling, pressure, humidity, etc. For the period of extended operation, the Environmental Qualification of Electric Components Program requires VYNPS to update the environmental qualification document to reflect the additional life. The environmental conditions (both ambient and accident) resulting from EPU are the basis for evaluations and analysis going forward. This is consistent with the description of the Environmental Qualification of Electric Components Program in the LRA. The staff finds the applicant's response acceptable because the Environmental Qualification ofElectric Components Program is an existing program established to meet VYNPS commitments in accordance with 10 CFR 50.49. The program considers equipment degradation from EPU radiation dose, normal and accident (LOCA, high energy line break) temperatures as well as cycling, pressure, humidity, etc. Compliance with 10 CFR 50.49 provides reasonable assurance that components can perform their intended functions during accident conditions after experience the effects of inservice aging.The staff reviewed those portions of the applicant's Environmental Qualification of ElectricComponents Program for which the applicant claimed consistency with GALL AMP X.E1 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicant's Environmental Qualification of Electric Components Program provided assurance that the applicant's environmental qualification program provided assurance of aging management of thermal, radiation, and cyclical for electrical equipment, 3-14important to safety and located in harsh environments. The staff finds the applicant'sEnvironmental Qualification of Electric Components Program acceptable because it conformed to the recommended GALL AMP X.E1, "Environmental Qualification of Electric Components."Operating Experience. LRA Section B.1.10 states that Licensee Event Report 97-20 notified thestaff of significant program deficiencies including nonconservative analytical methods.
Supplementary and confirmatory analyses were completed because the environmental qualification analyses were determined to be nonconservative. This operating experience demonstrates that the corrective action process documents program deficiencies and tracks corrective actions when necessary. QA audits in 2000 and 2002 identified deficiencies in maintenance and content of program documentation. However, a 2004 QA audit and engineering program health report determined that the program is effective and that its administration and maintenance meet regulatory requirements and commitments. The applicant further states that the VYNPS program is in compliance with 10 CFR 50.49. Therefore, the VYNPS program is effective at managing aging effects for electric components.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. On the basis of its review of the operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Environmental Qualification of Electric Components Program willadequately manage the aging effects that are identified in the LRA for which this AMP is credited.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.10, the applicant provided the UFSAR supplementfor the Environmental Qualification of Electric Components Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Environmental Qualification ofElectric Components Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-153.0.3.1.2  Flow-Accelerated Corrosion ProgramSummary of Technical Information in the Application. LRA Section B.1.13 describes the existingFlow-Accelerated Corrosion Program as consistent with GALL AMP XI.M17, "Flow-Accelerated Corrosion." This program applies to safety-related and nonsafety-related carbon steel components insystems carrying two phase or single phase high energy fluid greater than or equal to two percent of plant operating time. The program, based on Electric Power Research Institute (EPRI) Report NSAC-202L-R2 recommendations for an effective flow-accelerated corrosion program, predicts, detects, and monitors Flow-accelerated corrosion in plant piping and other pressure-retaining components. This program includes (a) an evaluation to determine critical locations, (b) initial operational inspections to determine the extent of thinning at these locations, and (c) followup inspections to confirm predictions or repair or replace components as necessary.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP.The staff reviewed the VYNPS Flow-accelerated corrosion procedures and noted that VYNPSperforms wall thickness examinations in areas adjacent to those locations where the detected wall thickness was less than predicted, and in similar locations in parallel trains, as recommended by EPRI Report NSAC-202L-R2. The staff noted that VYNPS had performed calculations to determine the required minimum wall thickness for all classes of piping, safety-related and nonsafety-related, and applied the results to its Flow-accelerated corrosion procedure acceptance criteria. The impact of the 20 percent increased power level on Flow-accelerated corrosion was evaluated in the SER for the EPU license amendment. In the staff's SER for EPU dated March 2, 2006, the staff found that the CHECWORKS modeling would be updated to account for uprated power conditions. The staff also noted that VYNPS calculates the number of operating cycles remaining before each component reaches its minimum allowable wall thickness, as recommended by CHECWORKS.In a letter dated January 31, 2004, VYNPS provided information on typical expected wallthickness changes due to Flow-accelerated corrosion in the main steam drains, moisture separator drains, and turbine across around piping subsequent to power uprate. In this letter, the applicant provided its expected changes to its Flow-Accelerated Corrosion Program. The applicant described the changes to criteria for the selection of piping components for inspection and sample expansion guidelines. The staff noted that the selection criteria were based on CHECWORKS database, Vermont Yankee operation, and industry operating experience on pipe wall thinning. Computer programs, such as CHECWORKS, used to predict and track pipe wall thicknesses as a result of Flow-accelerated corrosion are benchmarked against a general range of plant parameters including flow rate. The staff reviewed the changes to the Flow-Accelerated Corrosion Program and finds that after change the parameters remain in the range that was benchmarked. The staff concluded that, with the changes, the applicant will be able to reestablish the wear rate for those piping which may be impacted by power uprate. On this basis, the staff found the applicant's modified Flow-Accelerated Corrosion Program acceptable.
3-16The staff reviewed those portions of the applicant's Flow-Accelerated Corrosion Program forwhich the applicant claimed consistency with GALL AMP XI.M17 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicant's Flow-Accelerated Corrosion Program provided assurance that the aging effects due to Flow-accelerated corrosion will be adequately managed during the period of extended operation. The staff finds the applicant's Flow-Accelerated Corrosion Program acceptable because it conformed to the recommended GALL AMP XI.M17, "Flow-Accelerated Corrosion."Operating Experience. LRA Section B.1.13 states that recent inspection results (refuelingoutage (RFO) 23) revealed that repairs or replacements were not necessary. Turbine cross-around piping inspections found that 1995 repairs mitigated the rate of erosion and that wall thickness is acceptable. Absence of loss of material due to Flow-Accelerated Corrosion Program proves that the program is effective for managing loss of material for carbon steel lines containing high-energy fluids. Past repairs, replacements, and modifications also havebeen effective in mitigating Flow-Accelerated Corrosion Program. QA surveillances and self-assessments from 1999 to 2004 revealed no issues or findings that could impact program effectiveness.The applicant also stated that its has a comprehensive operating experience program thatmonitors industry events and issues, and assesses them for applicability to its own operations.
In addition, VYNPS has a corrective action program (CAP) that is used to track, trend, and evaluate significant plant issues and events. Those issues and events, whether from the industry or plant-specific, that are potentially significant to the Flow-Accelerated Corrosion Program at VYNPS are evaluated. The Flow-Accelerated Corrosion Program is augmented, as appropriate, when these evaluations show that changes to this program will enhance its effectiveness.In addition, the applicant stated that NRC inspection reports, audits, self assessments, and theCAP for VYNPS were reviewed for pertinent information; however, no findings indicating that the Flow-Accelerated Corrosion Program was ineffective were identified. Some findings identified Flow-Accelerated Corrosion Program weaknesses, which resulted in corrective actions and program enhancements. The staff reviewed the operating experience provided in the LRA, and interviewed theapplicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the applicant's Flow-Accelerated Corrosion Program, with the corrective actions and enhancements mentioned above, has been effective in identifying, monitoring, and correcting the effects of Flow-accelerated corrosion and can be expected to ensure that piping wall thickness will be maintained above the minimum required by design.On the basis of its review of the operating experience and discussions with the applicant'stechnical personnel, the staff concludes that the applicant's Flow-Accelerated Corrosion Program will adequately manage the aging effects that are identified in the LRA for which this AMP is credited.
3-17The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.14, the applicant provided the UFSAR supplementfor the Flow-Accelerated Corrosion Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Flow-Accelerated CorrosionProgram, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.1.3  Non-Environmental Qualification Inaccessible Medium-Voltage Cable ProgramSummary of Technical Information in the Application. LRA Section B.1.17 describes the newNon-Environmental Qualification Inaccessible Medium-Voltage Cable Program as consistentwith GALL AMP XI.E3, "Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." In this program, periodic actions like inspecting for water collection in cable manholes andconduit and draining water as needed will be taken to prevent cable exposure to significant moisture. In-scope medium-voltage cables exposed to significant moisture and voltage will be tested for an indication of the condition of the conductor insulation. The specific type of test will be determined prior to the initial test. The program will be implemented prior to the period of extended operation.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP.The staff noted that GALL AMP XI.E3, in accordance with the detection of aging effects programelement, recommends that the inspection for water collection should be performed based on actual plant experience with water accumulation in the manhole. However, the inspection frequency should be at least once every two years. In the program basis document, in accordance with the same attribute, VYNPS requires inspection for water collection in cable manholes and conduit at least once every two years. It was not clear to the staff that actual plant experience would be considered in the manhole inspection frequency. The staff asked the 3-18applicant to explain how actual plant experience was considered in the manhole inspectionfrequency, as consistent with the GALL Report's recommendation. In its response, the applicant stated that Non-EQ Inaccessible Medium-Voltage Cable Program will be revised to include the following: VYNPS inspection for water accumulation in manholes is conducted by a plantprocedure. An evaluation per the Corrective Action Process will be used to determine the need to revise manhole inspection frequency based on inspection
 
results. The staff finds the applicant's response acceptable because actual plant operating experiencewill be used to determine the manhole inspection frequency. However, the inspection frequency should be at least once every two years. This is consistent with GALL AMP XI.E3. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.17 as described above.The staff also noted that GALL AMP XI.E3, in accordance with the program description,recommends, in part, that periodic actions be taken such as inspecting for water collection in cable manholes and draining water, as needed, to prevent cables from being exposed to significant moisture. The above actions are not sufficient to assure water is not trapped elsewhere in the raceways. In addition to the periodic actions, in-scope inaccessiblemedium-voltage cables are tested to verify the condition of the conductor insulation. In the program basis document, in accordance with the same attribute, VYNPS stated that periodic actions will be taken to prevent cables from being exposed to significant moisture, such as inspecting for water collection in cable manholes and draining water, as needed. In-scope medium-voltage cables exposed to significant moisture and voltage will be tested to provide an indication of the condition of the conductor insulation. It was not clear to the staff if periodic action would be used to preclude cable testings. The staff asked the applicant to confirm that the intent of its Non-EQ Inaccessible Medium-Voltage Cable Program is to test in-scope cables andinspect water accumulation regardless of whether or not water accumulates in the manholes. In its response, the applicant stated that the intent of its Non-EQ Inaccessible Medium-Voltage Cable Program is to inspect for water in manholes and to test in-scope medium voltage cables.
The staff finds the applicant's response acceptable.In addition, the staff noted that GALL AMP XI.E3 recommends testing of all non-environmentalqualification inaccessible medium-voltage cables within the scope of license renewal. The staffasked the applicant to confirm that all inaccessible medium-voltage cables within the scope of license renewal are tested. The applicant responded that all of the in-scope medium-voltage cables will be subject to testing per the program requirements. The staff finds the applicant's response acceptable because it is consistent with the GALL Report's recommendation.Further, the staff noted that GALL AMP XI.E3, in accordance with the parametersmonitored/inspected program element, recommends that the specific type of test performed will be determined prior to the initial test. Moreover, that it is a proven test for detecting deterioration of the insulation system due to wetting such as power factor, partial discharge test, or polarization index, as described in an EPRI technical report, or other test that is state-of-the-art 3-19at the time the test is performed. In the program basis document, in accordance with the sameattribute, the applicant stated that the specific type of test performed will be determined prior to initial test. The staff asked the applicant to revise its program basis document to be consistent with the GALL Report or explain how it ensured that the test to be performed will be in accordance with industry guidelines. In its response, the applicant stated that it would revise the LRA to replace the last sentence in the Program Description with:The specific type of test to be performed will be determined prior to the initial testand is to be a proven test for detecting deterioration of the insulation system due to wetting as described in the EPRI technical report or other testing that is state-of-the-art at the time the test is performed.The staff finds the applicant's response acceptable because it is consistent with the GALLReport in that the type of test will be in accordance with industrial guidelines as described in EPRI technical report or another test that is state-of-the-art at the time the test is performed. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.17 as described above.Finally, the staff noted that GALL AMP XI.E3 defines a medium-voltage cable as having avoltage level from 2kV to 35kV. The applicant's Non-EQ Inaccessible Medium-Voltage Cable Program defines a medium-voltage cable as having a voltage level from 2kV to 15kV. The staff asked the applicant to revise the scope of inaccessible medium-voltage levels to be consistent with the GALL Report or provide a technical basis of why the water tree phenomenon is not applicable to a voltage level greater than 15kV. In its response, the applicant stated that VYNPS does not have any in-scope medium-voltage cable that is greater than 15kV. The applicant also stated that they would revise LRA Section B.1.17 to state medium-voltage cables include cableswith operating voltage level from 2kV to 35kV. The staff finds the applicant's response acceptable because the scope of the program would be consistent with the GALL Report. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.17 as described above.The underground power lines, which run from the adjacent Vernon Hydroelectric Station (VHS)to station switchgear, have been designated as the station blackout (SBO) alternate ac (AAC) source. Thus, they are used to meet SBO requirements 10 CFR 50.63. During the audit and review, the staff asked the applicant if all of these cables were included within the scope of VYNPS AMP B.1.17. The applicant replied that the underground power lines that run from the Vernon Dam switchyard to VYNPS safety-related buses are included in VYNPS AMP B.1.17.
The staff noted that there are other underground medium-voltage cables which run from VHS generators to the Vernon Dam switchyard that are not included within the scope of the applicant's Non-EQ Inaccessible Medium-Voltage Cable Program. The staff issuedRAI 3.6.2.2-N-08-3 to address this concern, which is evaluated in SER Section 3.6.2.3.2. The staff reviewed those portions of the applicant's Non-Environmental QualificationInaccessible Medium-Voltage Cable Program for which the applicant claimed consistency withGALL AMP XI.E3 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicant's Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program provided assurance of aging management of conductor insulation due to significant moisture while energized. The staff finds the applicant's Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program acceptable 3-20because it conforms to the recommended GALL AMP XI.E3, "Inaccessible Medium-VoltageCables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements."Operating Experience. LRA Section B.1.17 states that there is no operating experience for thenew Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program.During the audit and review, the staff noted that GALL AMP X1.E3, in accordance with operatingexperience, has shown that cross-linked polyethylene or high molecular weight polyethylene insulation materials are most susceptible to water tree formation. The formation and growth of water trees varies directly with operating voltage. Also, minimizing exposure to moisture minimizes the potential for the development of water treeing. As additional operating experience is obtained, lessons learned can be used to adjust the program, as needed. In VYNPS AMP B.1.17, the applicant stated that its Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program is a new program for which there is no operating experience.
The staff asked the applicant to address industrial and plant-specific operating experience and confirm that the review did not reveal any degradation not bound by industrial experience. In its response, the applicant stated that it would replace the operating experience discussion in LRA Section B.1.17 with the following:This program is a new AMP. Industry experience that forms the basis for theprogram is described in the operating experience element of NUREG-1801 program description. VYNPS plant-specific operating has been reviewed against the industry operating experience identified in NUREG-1801. Although VYNPS has not experienced all of the aging effects listed in NUREG-1801, the VYNPS program will manage all of the aging effects identified in the operating experience section of NUREG-1801. The program is based on the program description in NUREG-1801, which in turn is based on relevant industry operating experience.
As such, this program will provide assurance that effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the CLB for the period of extended operation. As additional operating experience is obtained, lessons learned can be used to adjust the program, as needed.The staff finds the applicant's response acceptable because the applicant reviewed theplant-specific operating experience against the industry experience identified in the GALL Report. As additional operating experience is obtained, lessons learned can be used to adjust the program elements. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.17 in accordance with operating experience as described above.The applicant also stated that operating experience at VYNPS is controlled by its operatingexperience program procedure. VYNPS plant-specific operating experience was reviewed in the applicable program basis document, as documented in the Audit and Review Report, and the results showed that VYNPS has had operating experience that is consistent with industry experience or with the GALL Report aging mechanisms. No new aging mechanism or operating experience was found that is not consistent with industry experience and the GALL Report.
3-21The operating experience program procedure includes the following components:Operating experience - Information received from various industry sources thatdescribes events, issues, equipment failures, that may represent opportunities to apply lessons learned to avoid negative consequences or to recreate positive experience as applicable.Internal operating experience - Operating experience that originates as acondition report or request from plant personnel which warrants consideration for possible Entergy-wide distribution. Internal operating experience can originate from any Entergy plant or headquarters.Impact Evaluation - Analysis of an operating experience event or problem thatrequires additional information and research to determine impact or potential impact, as it relates to plant condition and/or configuration. Impact evaluations are typically documented with a condition report. Condition report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. In addition, the staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.19, the applicant provided the UFSAR supplement forthe Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program.The applicant committed (Commitment #13) to implement its Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program by March 21, 2012.The staff reviewed LRA A.2.1.19 and determined that, upon the implementation of Commitment#13, the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Non-EnvironmentalQualification Inaccessible Medium-Voltage Cable Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-223.0.3.1.4  Non-Environmental Qualification Instrumentation Circuits Test Review ProgramSummary of Technical Information in the Application. LRA Section B.1.18 describes the newNon-Environmental Qualification Instrumentation Circuits Test Review Program as consistent with GALL AMP XI.E2, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits." The Non-Environmental Qualification Instrumentation Circuits Test Review Program will assuremaintenance of the intended functions of instrument cables exposed to adverse environments of heat, radiation, and moisture consistent with the CLB through the period of extended operation.
An adverse environment is significantly more severe than the service environment specified for the cable. This program will consider the technical information and guidance of NUREG/CR-5643, Institute of Electrical and Electronics Engineers Std. P1205, SAND96-0344, and EPRI TR-109619. The program will start prior to the period of extended operation.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP.The staff noted that GALL AMP XI.E2 recommends that in cases where the calibration orsurveillance program does not include a cabling system in the testing circuit (cables disconnected during instrument calibration), the cable testing frequency shall be determined by the applicant based on an engineering evaluation, but the test frequency shall be at least one every ten years. LRA Section A.2.1.20 stated that for cable disconnected during instrument calibration, testing is performed at least once every 10 years. As documented in the Audit and Review Report, the staff asked the applicant to explain how an engineering evaluation is considered in the test frequency; in order to be consistent with the GALL Report's recommendation. In its response, the applicant stated that it would revise LRA Section B.1.18 as follows:The first test of neutron monitoring system cables that are disconnected duringinstrument calibration shall be completed before the period of extended operation and subsequent tests will occur at least every 10 years. In accordance with the CAP, an engineering evaluation will be performed when test acceptance criteria are not met and corrective actions, including modified inspection frequency, will be implemented to ensure that the intended functions of the cables can be maintained consistent with the CLB for the period of extended operation.The staff finds the applicant's response acceptable because an engineering evaluation will beconsidered in the test frequency to ensure that the intended function of in-scope cables is maintained. This is consistent with GALL AMP XI.E2. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.18 as described above.
3-23The staff also noted that GALL AMP XI.E2, in accordance with the corrective actions programelement, recommends that an evaluation is to consider the significance of the test results, the operability of the component, the reportability of the event, the extent of the concern, the potential root causes for not meeting the test acceptance criteria, the corrective actions required, and likelihood of recurrence, in addition to 10 CFR Part 50, Appendix B requirements.The applicable program basis document, in accordance with the same program element, onlyreferred to requirements of 10 CFR Part 50 Appendix B to address the corrective actions. The staff asked the applicant to revise the "corrective actions" program element to be consistent with the GALL Report or provide a justification of why such specific actions were not necessary. The applicant responded that VYNPS AMP B.1.18, in accordance with the CAP element, stated that "an engineering evaluation will be performed when the test acceptance criteria are not met in order to ensure that the intended functions of the electrical cables can be maintained consistentwith current license basis." This evaluation is performed in accordance with the Entergy corrective action process procedure. This procedure provides the stated elements to consider including the extent of the concern, the potential root causes for not meeting the test acceptance criteria, the corrective action required, and likelihood of recurrence. The staff finds the applicant's response acceptable because corrective actions per the corrective action process procedure will require specific actions consistent with to the GALL AMP XI.E2 corrective actions.In addition, GALL AMP XI.E2, in accordance with the scope of program element, stated that thisprogram applies to electrical cables and connections used in circuits with sensitive, high-voltage,low-level signal (i.e., radiation monitoring), and nuclear instrumentation that are subject to anAMR. As documented in the Audit and Review Report, the applicable program basis document, in accordance with the same program element, did not include the high-range radiation monitoring cables. The staff asked the applicant to clarify why high-range radiation monitor cables were not included within the scope of its Non-EQ Instrumentation Circuits Test Review Program. The applicant responded, as documented in the Audit and Review Report, that cables and connections in the high-range reactor building area monitoring system, support a license renewal intended function. However, the entire length of these cables are environmental qualified and do not require aging management since they are subject to replacement based on a qualified life. The staff reviewed the applicant's response and finds the applicant's responseacceptable because the entire length of high-range radiation monitoring cables are environmentally qualified, subject to 10 CFR 50.49 requirements, and do not require an AMR.Furthermore, GALL AMP XI.E2, in accordance with the parameters monitored/inspectedprogram element, stated that the parameters monitored are determined from the specific calibration, surveillance, or testing performed and are based on the specific instrumentation in accordance with surveillance or being calibrated as documented in plant procedures. As documented in the Audit and Review Report, the applicable program basis document, in accordance with the same attribute, stated that the results from calibration or surveillance of components within the scope of license renewal will be reviewed. The parameters reviewed will be based on the specific instrumentation circuit in accordance with surveillance or being calibrated, as documented in the plant calibration or surveillance procedures. The staff asked the applicant to explain why the review of calibration results belong to the parameters monitored/inspected attribute and why the parameter for cable testing was not mentioned. The staff also asked the applicant to confirm that cable testing will be performed on in-scope cables disconnected during instrument calibration. In its response, the applicant stated that its Non-EQ 3-24Instrumentation Circuits Test Review Program basis document will be revised in accordance withthe parameters monitored/inspected program element to state that the parameters monitored are determined from the specific calibration, surveillance or testing performed and are based on the specific instrumentation circuit in accordance with surveillance or being calibrated, as documented in plant procedures. Cable testing is performed by plant procedures on cables within the scope of GALL AMP XI.E2 that are disconnected during instrument calibration. The staff verified, as documented in the Audit and Review Report, that the applicant incorporated this change in the program basis document. The staff finds the applicant's response acceptable because the revised parameters monitored/inspected program element is consistent with GALL AMP XI.E2.The staff reviewed those portions of the applicant's Non-Environmental QualificationInstrumentation Circuits Test Review Program for which the applicant claimed consistency with GALL AMP XI.E2 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicant's Non-Environmental Qualification Instrumentation Circuits Test Review Program provided assurance of aging management of conductor insulation due to heat, radiation, or moisture for electrical cables used in instrumentation circuits. The stafffinds the applicant's Non-Environmental Qualification Instrumentation Circuits Test Review Program acceptable because it conformed to the recommended GALL AMP XI.E2.Operating Experience. LRA Section B.1.18 states that there is no operating experience for thenew Non-Environmental Qualification Instrumentation Circuits Tests Review Program. Industry and plant-specific operating experience will be considered in the development of this program, and future operating experience will be incorporated into the program appropriately.During the audit and review, the staff noted that GALL AMP XI.E2, in accordance with theoperating experience, stated that operating experience has identified a case where a change in temperature across a high range radiation monitor cable in containment resulted in a substantial change in the reading of the monitor. Changes in instrument calibration can be caused by degradation of the circuit cable and are a possible indication of electrical cable degradation. Thevast majority of site specific and industry wide operating experience regarding neutron flux instrumentation circuits is related to cable/connector issues inside containment near the reactorvessel. The staff asked the applicant to address industrial and plant-specific operating experience and confirm that plant-specific operating experience did not reveal any degradation not bound by industry experience. In its response, the applicant stated that operating experience discussion in LRA Section B.1.18 would be replaced with the following:This program is a new AMP. Industry experience that forms the basis for theprogram is described in the operating experience element of NUREG-1801's program description. VYNPS plant-specific operating have been reviewed against the industry operating experience identified in NUREG-1801. Although VYNPS has not experienced all of the aging effects listed in NUREG-1801, the VYNPS program will manage all of the aging effects identified in the Operating Experience section of NUREG-1801. The program is based on the program description in NUREG-1801, which in turn is based on relevant industry operating experience. As such, this program will provide assurance that effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the CLB for the period of extended operation.
3-25As additional operating experience is obtained, lessons learned can be used toadjust the program, as needed.The staff finds the applicant's response acceptable because the applicant reviewed theplant-specific operating experience against the industry experience identified in the GALL Report. As additional operating experience is obtained, lessons learned can be used to adjust the program elements. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.18 in accordance with operating experience as described above.The applicant also stated that operating experience at VYNPS is controlled by its operatingexperience program procedure. The staff reviewed the plant-specific operating experience in the applicable program basis document and the results showed that VYNPS has had operating experience that is consistent with industry experience or with the GALL Report aging mechanisms. No new aging mechanism or operating experience was found that is not consistent with industry experience and the GALL Report.The operating experience program procedure includes the following components:Operating experience - Information received from various industry sources thatdescribes events, issues, equipment failures, that may represent opportunities to apply lessons learned to avoid negative consequences or to recreate positive experience as applicable.Internal operating experience - Operating experience that originates as acondition report or request from plant personnel which warrants consideration for possible Entergy-wide distribution. Internal operating experience can originate from any Entergy plant or headquarters.Impact Evaluation - Analysis of an operating experience event or problem thatrequires additional information and research to determine impact or potential impact, as it relates to plant condition and/or configuration. Impact evaluation are typically documented with a condition report. Condition report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.20, the applicant provided the UFSAR supplement forthe Non-Environmental Qualification Instrumentation Circuits Test Review Program.
3-26The applicant committed (Commitment #14) to implement its Non-Environmental QualificationInstrumentation Circuits Test Review Program by March 21, 2012.The staff reviewed LRA Section A.2.1.20 and determined that, upon the implementation ofCommitment #14, the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Non-EnvironmentalQualification Instrumentation Circuits Test Review Program, the staff finds all program elements consistent with the GALL Report with the addition of Commitment #14. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.1.5  Non-Environmental Qualification Insulated Cables and Connections Program Summary of Technical Information in the Application. LRA Section B.1.19 describes the newNon-Environmental Qualification Insulated Cables and Connections Program as consistent with GALL AMP XI.E1, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." The Non-Environmental Qualification Insulated Cables and Connections Program will assuremaintenance of the intended functions of insulated cables and connections exposed to adverse environments of heat, radiation, and moisture consistent with the CLB through the period of extended operation. An adverse environment is significantly more severe than the service environment specified for the insulated cable or connection. A representative sample of accessible insulated cables and connections within the scope of license renewal will be inspected visually for such cable and connection jacket surface anomalies as embrittlement, discoloration, cracking, or surface contamination. The technical basis for sampling will be determined in accordance with EPRI TR-109619, "Guideline for the Management of Adverse Localized Equipment Environments." The program will start prior to the period of extended operation. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP.The staff noted that, in accordance with the program description, GALL AMP XI.E1, stated thatthe program described herein is written specifically to address cables and connections at plants whose configuration is such that most (if not all) cables and connections installed in adverse localized environments are accessible. This program, as described, can be thought of as a sampling program. Selected cables and connections from accessible areas (the inspection sample) are inspected and represent, with assurance, all cables and connections in the adverse localized environments. If an unacceptable condition or situation is identified for a cable or connection in the inspection sample, a determination is made as to whether the same condition or situation is applicable to other accessible or inaccessible cables or connections. In the 3-27Non-EQ Insulated Cables and Connections Program in accordance with the same element, theapplicant stated that a representative sample of accessible insulated cables and connections, within the scope of license renewal, will be visually inspected for cable and connection jacket surface anomalies such as embrittlement, discoloration, cracking or surface contamination. The technical basis for sampling will be determined using an EPRI technical report document. The staff asked the applicant to explain the technical basis for cable sampling to be consistent with the GALL Report's program description. In its response, the applicant stated that to clarify the technical basis for sampling, the sampling discussion in LRA Section B.1.19 for the Non-Environmental Qualification Insulated Cables and Connections Program would be revised to read as follows:This program addresses cables and connections at plants whose configuration issuch that most cables and connections installed in adverse localized environments are accessible. This program can be thought of as a sampling program. Selected cables and connections from accessible areas will be inspected and represent, with assurance, all cables and connections in the adverse localized environments. If an unacceptable condition or situation is identified for a cable or connection in the inspecting sample, a determination will be made as to whether the same condition or situation is applicable to other accessible cables or connections. The sample size will be increased on an evaluation per the plant Corrective Action Process procedure.The staff finds the applicant's response acceptable because it provided the technical basis forcable sampling; these basis are consistent with the GALL Report's program description. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.19 as described above.In addition, GALL AMP XI.E1, in accordance with the scope of program element, stated that theinspection program applies to accessible electrical cables and connections within the scope of license renewal that are installed in adverse localized environment caused by heat or radiation in the presence of oxygen. The Non-EQ Insulated Cables and Connections Program program basis document, in accordance with the same element, stated that this program will include accessible insulated cables and connections installed in structures within the scope of license renewal and prone to adverse localized environments. It was not clear to the staff if the scope of the program only included insulated cables and connections installed in-scope structures located in adverse localized environment or insulated cables and connections within the scope of license renewal that are installed in adverse localized environments. The staff asked the applicant to clarify the scope of the program, as appropriate.
In its response, the applicant stated that "in a structure" meant inside the plant, not outside. It would revise LRA Section B.1.19 Program Description to include the following:The program applies to accessible electrical cables and connections within thescope of license renewal that are installed in adverse localized environments caused by heat or radiation in the presence of oxygen.The staff finds the applicant's response acceptable because the scope of VYNPS AMP B.1.19will be consistent with the scope of GALL AMP XI.E1 and it will remove the confusion as described above. In a letter dated July 14, 2006, the applicant revised the program description in LRA Section B.1.19 as described above.
3-28The staff reviewed those portions of the applicant's Non-Environmental Qualification InsulatedCables and Connections Program for which the applicant claimed consistency with GALL AMP XI.E1 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicant's Non-Environmental Qualification Insulated Cables and Connections Program provided assurance of aging management of cables and connectors within the scope of license renewal exposed to adverse localized temperature, moisture, or radiation environments with the presence of oxygen. The staff finds the applicant's Non-Environmental Qualification Insulated Cables and Connections Program acceptable because it conformed to the recommended GALL AMP XI.E1.Operating Experience. LRA Section B.1.19 states that there is no operating experience for thenew Non-Environmental Qualification Insulated Cables and Connections Program.During the audit and review, the staff noted that GALL AMP XI.E1 stated that operatingexperience has shown that adverse localized environments caused by heat or radiation for electrical cables and connections may exist next to or above (within 3 feet of) steam generators, pressurizers or hot process pipes, such as feedwater (FW) lines. These adverse localized environments have been found to cause degradation of the insulating materials on electrical cables and connections that are visually observable, such as color changes or surface cracking.
These visual indications can be used as indicators of degradation. The staff asked the applicant to provide industrial and plant operating experience for this program and confirm that the review of plant operating experience did not reveal any degradation not bound by industry experience.
In its response, the applicant stated that it would replace the operating experience discussion in LRA Section B.1.19 with the following:This program is a new aging management program. Industry experience thatforms the basis for the program is described in the operating experience element of NUREG-1801 program description. VYNPS plant-specific operating experience has been reviewed against the industry operating experience identified in NUREG-1801. Although VYNPS has not experienced all of the aging effects listed in NUREG-1801, the VYNPS program will manage all of the aging effects identified in the Operating Experience section of NUREG-1801.The program is based on the program description in NUREG-1801, which in turnis based on relevant industry operating experience. As such, this program will provide assurance that effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the CLB for the period of extended operation. As additional operating experience is obtained, lessons learned can be used to adjust the program, as needed.The staff finds the applicant's response acceptable because the applicant reviewed theplant-specific operating experience against the industry experience identified in the GALL Report. As additional operating experience is obtained, lessons learned will be used to adjust the program elements as needed. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.19 in accordance with operating experience as described above.The applicant also stated that operating experience at VYNPS is controlled by its operatingexperience program procedure. VYNPS plant-specific operating experience was reviewed in the 3-29applicable program basis document, as documented in the Audit and Review Report, and theresults showed that VYNPS has had operating experience that is consistent with industry experience or with the GALL Report aging mechanisms. No new aging mechanism or operating experience was found that is not consistent with industry experience and the GALL Report.Operating experience at VYNPS is controlled by an operating experience program procedure.The program includes the following components:Operating experience - Information received from various industry sources thatdescribes events, issues, equipment failures, that may represent opportunities to apply lessons learned to avoid negative consequences or to recreate positive experience as applicable.Internal operating experience - Operating experience that originates as acondition report or request from plant personnel which warrants consideration for possible Entergy-wide distribution. Internal operating experience can originate from any Entergy plant or headquarters.Impact Evaluation - Analysis of an operating experience event or problem thatrequires additional information and research to determine impact or potential impact, as it relates to plant condition and/or configuration. Impact evaluation are typically documented with a condition report. Condition report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. In addition, the staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.21, the applicant provided the UFSAR supplement forthe Non-Environmental Qualification Insulated Cables and Connections Program.The applicant committed (Commitment #15) to implement its Non-EQ Insulated Cables andConnections Program by March 21, 2012.The staff reviewed LRA Section A.2.1.21 and determined that, upon the implementation ofCommitment #15, the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d).
3-30 Conclusion. On the basis of its audit and review of the applicant's Non-EnvironmentalQualification Insulated Cables and Connections Program, the staff finds all program elements consistent with the GALL Report with the addition of Commitment #15. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.1.6  One-Time Inspection Program Summary of Technical Information in the Application. LRA Section B.1.21 and subsequent LRA supplements describe the new One-Time Inspection Program as consistent with GALL AMPs XI.M32, "One-Time Inspection," and XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." The One-Time Inspection Program will be implemented prior to the period of extendedoperation. The one-time inspection activity for small-bore piping in the reactor coolant system and associated systems that form the reactor coolant pressure boundary (RCPB) will be comparable to GALL AMP XI.M35. The program will verify AMP effectiveness and confirm the absence of aging effects for the following:
* water chemistry control programs
* internal carbon steel surfaces exposed to indoor air in the standby gas treatment system
* diesel fuel monitoring program
* non-piping components without metal fatigue analysis
* oil analysis program
* carbon steel retired in place system components in the area around containmentpenetration X-21
* small bore piping in the reactor coolant system and associated systems that form thereactor coolant pressure boundary
* reactor vessel flange leakoff lines
* main steam flow restrictors (cast austenitic stainless steel)The elements of the program include (a) determination of the sample size based on anassessment of materials of fabrication, environment, plausible aging effects, and operating experience; (b) identification of the inspection locations in the system or component based on the aging effect; (c) determination of the examination technique, including acceptance criteria that would be effective in managing the aging effect for which the component is examined; and (d) evaluation of the need for followup examinations to monitor the progression of any aging degradation.
3-31Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP.The staff asked the applicant to clarify how VYNPS does volumetric examinations of small borepiping socket welds. In a letter dated July 6, 2006, the applicant committed (Commitment # 16) to include an addition to its One-Time Inspection Program. Specifically, the applicant committed to a destructive or non-destructive examination of one (1) socket welded connection using techniques proven by past industry experience to be effective for the identification of cracking in small bore socket welds. Furthermore, the applicant committed that, should an inspection opportunity not occur (e.g., socket weld failure or socket weld replacement), a susceptible small-bore socket weld will be examined either destructively or non-destructively prior to entering the period of extended operation. Since small-bore piping socket weld connection will be either destructively or non-destructively examined at least once, the staff found the applicant's response acceptable.Upon further discussions, the staff concluded that the destructive or non-destructive examinationof one or more socket welds would not contribute significant additional information on the condition of the socket welds. Socket welds fail by vibrational fatigue with cracks initiating from their inside surfaces. The time required for fatigue crack initiation is very long compared to the time to propagate through a wall. Therefore, a surface examination or destructive examination of a socket weld is unlikely to detect problems. In addition, there is no history of significant socket weld failures.In its letter dated March 12, 2007, the applicant revised Commitment #16 to remove referencesto socket welds.In addition, as discussed further in SER Sections 3.2.2.1.3 and 3.3.2.1.9, the applicant providedan amendment to its LRA in a letter dated July 14, 2007, to state that its One-Time Inspection Program will verify the effectiveness of the Oil Analysis Program, and the Diesel Fuel Monitoring Program by confirming the absence of loss of material, cracking and fouling, where applicable. The applicant also stated in the LRA that when evidence of an aging effect is revealed by aone-time inspection, routine evaluation of the inspection results will identify appropriate corrective actions. The inspection will be performed within the 10 years prior to the period of extended operation.The staff reviewed those portions of the applicant's One-Time Inspection Program for which theapplicant claimed consistency with GALL AMP XI.M32 and GALL AMP XI.M35 and found that they are consistent with these GALL AMPs. On the basis of its review, the staff concludes that the applicant's One-Time Inspection Program provided assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's One-Time Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, "One-Time Inspection" and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping."
3-32Operating Experience. LRA Section B.1.21 states that there is no operating experience for thenew One-Time Inspection Program. Industry and plant-specific operating experience will be considered in the development of this program, as appropriate.The staff confirmed that the CAP, which captures internal and external plant operatingexperience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.23, the applicant provided the UFSAR supplement forthe One-Time Inspection Program.In addition, the applicant stated in a letter dated January 4, 2007, that a one-time inspectionactivity is used to verify the effectiveness of the water chemistry control programs by confirming that unacceptable cracking, loss of material, and fouling is not occurring on components within systems covered by water chemistry control programs [LRA Sections A.2.1.34, A.2.1.35, and A.2.1.36].The applicant committed (Commitment #16) to implement its One-Time Inspection Program byMarch 21, 2012.The staff reviewed LRA Section A.2.1.23 and determined that, upon the implementation ofCommitment #16, the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's One-Time InspectionProgram, the staff finds all program elements consistent with the GALL Report with the addition of Commitment #16. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.1.7  Selective Leaching Program Summary of Technical Information in the Application. LRA Section B.1.25 describes the newSelective Leaching Program as consistent with GALL AMP XI.M33, "Selective Leaching of Materials." The Selective Leaching Program will ensure the integrity of components made of cast iron,bronze, brass, and other alloys exposed to raw water, treated water, or groundwater that may cause selective leaching. The program will include a one-time visual inspection and hardness measurement of selected components that may be susceptible to determine whether loss of material due to selective leaching occurs and whether the loss will affect the ability of the 3-33components to perform their intended function for the period of extended operation. Theprogram will start prior to the period of extended operation.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The Audit and Review Report documents the details of the staff's evaluation of this AMP.The staff reviewed those portions of the applicant's Selective Leaching Program for which theapplicant claimed consistency with GALL AMP XI.M33 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicant's Selective Leaching Program provided assurance that this aging effect will be adequately managed during the period of extended operation. The staff finds the applicant's Selective Leaching Program acceptable because it conforms to the recommended GALL AMP XI.M33, "Selective Leaching of Materials."Operating Experience. LRA Section B.1.25 states that there is no operating experience for thenew Selective Leaching Program.The staff audited VYNPS maintenance data for evidence of this aging mechanism and reviewedthe operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. In addition, the staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirms that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.27, the applicant provided the UFSAR supplement forthe Selective Leaching Program.The applicant committed (Commitment #19) to implement its Selective Leaching Program byMarch 21, 2012.The staff reviewed LRA Section A.2.1.27 and determined that, upon the implementation ofCommitment #19, the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Selective Leaching Program,the staff finds all program elements consistent with the GALL Report with the addition of Commitment #19. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-343.0.3.1.8  Masonry Wall ProgramSummary of Technical Information in the Application. LRA Section B.1.27.1 describes theexisting Masonry Wall Program as consistent with GALL AMP XI.S5, "Masonry Wall Program." The objective of the Masonry Wall Program is to manage aging effects so that the evaluationbasis established for each masonry wall within the scope of license renewal remains valid through the period of extended operation. The program includes all masonry walls performing intended functions in accordance with 10 CFR 54.4. The included walls are the 10 CFR 50.48-required walls and masonry walls in the reactor building, intake structure, control room building, and turbine building. Masonry walls are visually examined at a frequency ensuring no loss of intended function between inspections.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP.During the audit and review, the staff noted that GALL AMP XI.S5, Masonry Wall Program, inaccordance with the detection of aging effects program element, has the following statement: The frequency of inspection is selected to ensure there is no loss of intendedfunction between inspections. The inspection frequency may vary from wall to wall, depending on the significance of cracking in the evaluation basis.
Unreinforced masonry walls, which have not been contained by bracing warrant the most frequent inspection, because the development of cracks may invalidate the existing evaluation basis. The staff asked the applicant to explain if the inspection frequency varies from wall to wall.
The applicant stated that the inspection of masonry walls which are within the scope of licenserenewal, are performed each refueling outage. Upon the completion of six successive surveillance intervals during a ten -year period, the sequence of the inspections revert back to the initial sequence interval. In addition, the applicant stated that due to the lack of aging effects (new cracking) for the masonry walls through the current life of the program, no individual masonry walls receive more frequent inspections over others. However, if significant new cracking was discovered on a particular masonry wall, part of the corrective action would entail more frequent inspections.The staff finds the applicant's response acceptable. A review of the applicant's operatingexperience did not reveal a history of masonry wall aging effects. For VYNPS, due to a history of no masonry wall aging effects, the CAP is an adequate method to determine if more frequent inspections should be performed on individual masonry walls beyond the program's current 10-year cycle.The staff reviewed those portions of the applicant's Structures Monitoring-Masonry WallProgram for which the applicant claimed consistency with GALL AMP XI.S5 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicant's Structures Monitoring-Masonry Wall Program demonstrated that the effects of aging 3-35of masonry block walls will be properly managed for the period of extended operation. The stafffinds the applicant's Structures Monitoring-Masonry Wall Program acceptable because it conformed to the recommended GALL AMP XI.S5, "Masonry Wall Program."Operating Experience. LRA Section B.1.27.1 states that recent inspections (2002 and 2004)revealed no cracking of masonry walls within the scope of license renewal potentially affecting wall qualification, proving that the program is effective in managing cracking for masonry and block walls. QA surveillance and self-assessment in 2002 and 2004 revealed no issues or findings that could impact program effectiveness. The listed operating experience in which inspections revealed no cracking which could potentially affect wall qualification demonstrated that the VYNPS Masonry Wall Program is effective in ensuring that age related deterioration of masonry walls within the scope of license renewal is adequately managed to ensure that these masonry walls maintain their ability to perform their intended function. The staff reviewed a sampling of drawings for masonry walls within the scope of license renewaland finds the drawings to be of high quality. Components attached to the walls were well documented with respect to component identification, overall dimensions and relative wall location. Any identified cracks were also well mapped out on the drawings as far as relative location and width. The high quality of the masonry drawings will ensure that any aging effects (new cracks) will be identified during the inspections performed in accordance with the program.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. In addition, the staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.29, the applicant provided the UFSAR supplement forthe Masonry Wall Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Masonry Wall Program, thestaff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-363.0.3.1.9  System Walkdown ProgramSummary of Technical Information in the Application. LRA Section B.1.28 describes the existingSystem Walkdown Program as consistent with GALL AMP XI.M36, "External Surfaces Monitoring." This program entails inspections of external surfaces of components subject to an AMR. Theprogram is also credited with managing loss of material from internal surfaces where internal and external material-environment combinations are the same and external surface conditions represent internal surface conditions.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP.The staff noted that, the applicant's System Walkdown procedure, one of the specific purposesof which was to observe and report system conditions, did not adequately address material degradation and leakage. Specifically, the procedure did not address the loss of material due to corrosion or material wastage, or surface or coating deterioration/degradation. Also, the procedure did not adequately address leakage or evidence of leakage from or onto surfaces.
The applicant agreed that the procedure should be enhanced to include periodic system engineer inspections which are aging management oriented. The applicant added that an additional enhancement would be provided to examiners who perform the system walkdowns using the recent guidance provided in the EPRI "Aging Management Field Guide" document.
The staff reviewed the guide and noted that it provided photos and detailed descriptions of the AERMs on the materials and in the environments that are found at nuclear power plants, and agreed that it would be a useful tool to the examiners.As discussed in SER Section 3.0.3.2.11, the applicant also committed to revise the SystemWalkdown Program to specify CO 2 system inspections every six months.The staff reviewed those portions of the applicant's System Walkdown Program for which theapplicant claimed consistency with GALL AMP XI.M36 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicant's System Walkdown Program provided assurance that the program will manage aging effects, e.g., the loss of material and leakage, of the external surfaces of components. The staff finds the applicant's System Walkdown Program acceptable because it conformed to the recommended GALL AMP XI.M36, "External Surfaces Monitoring."Operating Experience. LRA Section B.1.28 states that in 1999 a self-assessment determinedthat corrective actions for deficient conditions detected during system walkdowns had been effective and had received timely closeouts, assuring that the program will manage component loss of material. Peer assessment found that system engineering management had not used metrics sufficient for monitoring core functions of the department. In accordance with new oversight standards supervisors perform walkdowns with system engineers to satisfy quality expectations. Program oversight was increased during 2003, providing assurance that the program will manage component loss of material. Recent system walkdowns (2003 and 2004) of the circulating water (CW), standby liquid control (SLC), and reactor building heating, ventilation, 3-37and air-conditioning (HVAC) systems have detected leakage or degradation prior to loss ofintended function, proving that the program is effective for managing component loss of material.The applicant stated, during the audit and review, that VYNPS has a comprehensive operatingexperience program that monitors industry events and issues, and assesses them for applicability to its own operations. In addition, VYNPS has a CAP that is used to track, trend, and evaluate significant plant issues and events. Those issues and events, whether from the industry or plant-specific, that are potentially significant to the System Walkdown Program are evaluated. The System Walkdown Program is augmented, as appropriate, when these evaluations show that changes to this program will enhance its effectiveness. The staff reviewed a representative sample of system walkdowns. These system walkdownsindicated a higher than average number of reports dealing with the condenser and the SLC system. The applicant agreed that these were areas of concern. The staff noted that this program included thermography of plant instrumentation and the electrical components in the switchyard.The staff also reviewed the operating experience provided to confirm that the plant-specificoperating experience did not reveal any degradation not bounded by industry experience. The staff finds that the applicant reviewed all applicable operating experience and used this experience to modify the System Walkdown Program appropriately. This should help ensure that the System Walkdown Program will manage the effects of aging in the systems and components for which the program is credited.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.32, the applicant provided the UFSAR supplement forthe System Walkdown Program.The applicant committed (Commitment #24) to have the System Walkdown guidance documentenhanced to perform periodic system engineer inspections of systems in-scope and subject to an AMR for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3). Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject system will include SSCs that are in-scope and subjected to an AMR for license renewal in accordance with 10 CFR 54.4 (a)(2). The applicant also committed (Commitment #35) to provide within the System WalkdownTraining Program a process to document biennial refresher training of Engineers to demonstrate inclusion of the methodology for aging management of plant equipment as described in the EPRI "Aging Assessment Field Guide" or comparable instructional guide, by March 21, 2012.The applicant also committed (Commitment #30) to revise the System Walkdown Program tospecify CO 2 system inspections every six months; by March 21, 2012.
3-38The staff reviewed LRA Section A.2.1.32 and determined that, upon the implementation of(Commitments #24, #30 and #35), the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's System Walkdown Program,the staff finds all program elements consistent with the GALL Report with the addition of Commitments #24, #30, and #35. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.1.10  Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic StainlessSteel ProgramSummary of Technical Information in the Application. LRA Section B.1.29 describes the newThermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program as consistent with GALL AMP XI.M13, "Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS)." The purpose of the Thermal Aging and Neutron Irradiation Embrittlement of Cast AusteniticStainless Steel Program is to make sure that reduction of fracture toughness due to thermal aging and radiation embrittlement will not result in loss of intended function. This program will evaluate CASS components in the reactor vessel internals and require nondestructive examinations (NDEs) as appropriate. EPRI, the BWR Owners Group, and other industry groups focus on reactor vessel internals to better understand aging effects. Future Boiling Water Reactor Vessel Internals Project (BWRVIP) reports, EPRI reports, and other industry operating experience will be additional bases for evaluations and inspections in accordance with this program. This program will supplement reactor vessel internals inspections required by the BWR Vessel Internals Program for assurance that aging effects do not result in loss of the intended functions of reactor vessel internals during the period of extended operation. The program will start prior to the period of extended operation.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP.The staff reviewed those portions of the applicant's Thermal Aging and Neutron IrradiationEmbrittlement of Cast Austenitic Stainless Steel Program for which the applicant claims consistency with GALL AMP XI.M13 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicant's Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program will adequately maintain the integrity of CASS components during period of extended operation. The staff finds the applicant's Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program conforms to the recommended GALL AMP XI.M13, "Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS)."
3-39Operating Experience. LRA Section B.1.29 states that there is no operating experience for thenew Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program.The staff reviewed the operating experience provided in the program basis document, andinterviewed the applicant's technical personnel to conclude that no industry operating experience with thermal aging and embrittlement of CASS has emerged.The staff finds the CAP, which captures internal and external plant operating experience issues,will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.33, the applicant provided the UFSAR supplement forthe Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program.The applicant committed (Commitment #25) to implement its Thermal Aging and NeutronIrradiation Embrittlement of Cast Austenitic Stainless Steel Program by March 21, 2012.The staff reviewed LRA Section A.2.1.33 and determined that, upon the implementation ofCommitment #25, the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Thermal Aging and NeutronIrradiation Embrittlement of Cast Austenitic Stainless Steel Program, the staff finds all program elements consistent with the GALL Report with the addition of Commitment #25. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.1.11  Water Chemistry Control - BWR Program Summary of Technical Information in the Application. LRA Section B.1.30.2 describes theexisting Water Chemistry Control - BWR Program as consistent with GALL AMP XI.M2, "Water Chemistry." The objective of this program is to manage aging effects caused by corrosion and crackingmechanisms. The program monitors and controls water chemistry in accordance with EPRI Report 1008192 (BWRVIP-130), which has three sets of guidelines for primary water, for condensate and FW, and for control rod drive (CRD) mechanism cooling water. EPRI guidelines in BWRVIP-130 also include recommendations for controlling water chemistry in the torus, condensate storage tanks, demineralized water storage tanks, and spent fuel pool. The Water 3-40Chemistry Control - BWR Program optimizes the primary water chemistry to minimize thepotential for loss of material and cracking by limiting the levels of contaminants in the reactor coolant system that could cause loss of material and cracking. Additionally, the applicant has instituted hydrogen water chemistry for the reduction of dissolved oxygen in the treated water to limit the potential for intergranular stress corrosion cracking (IGSCC) through the reduction of dissolved oxygen in the treated water.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP. The staff reviewed those portions of the applicant's Water Chemistry Control-BWR Program forwhich the applicant claimed consistency with GALL AMP XI.M2 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicant's Water Chemistry Control-BWR Program provided assurance that this program will help mitigate degradation caused by corrosion and stress corrosion cracking (SCC) in components exposed to reactor or treated water. The staff finds the applicant's Water Chemistry Control-BWR Program acceptable because it conformed to the recommended GALL AMP XI.M2, "Water Chemistry."Operating Experience. LRA Section B.1.30.2 states that for the first 158 operating days of Cycle24 (May - November 2004), sulfate and chloride levels in the reactor water, while within EPRI guideline acceptance criteria, were significantly higher than they had been during Cycle 23. An engineering and chemistry evaluation determined the most probable sources of chloride and sulfate ingress and the causes contributing to the extended time required to reduce reactor water chemistry to normal low levels. Corrective actions included enhanced control of chemicalingress, increased condensate and FW cleaning, and enhanced demineralizer filter replacement procedures. Resolution of higher than normal reactor water sulfate and chloride levels before they exceed EPRI guideline acceptance criteria is assurance that the program will ensure adequate water quality to preclude component loss of material, cracking, and fouling. A QA audit in 2003 revealed no issues or findings that could impact program effectiveness.The staff reviewed a chemistry audit report for April 2005 from an independent externalorganization and verified that it identified areas of improvement for the FW and condensate system to maintain the performance quality of the Water Chemistry Control - BWR Program.The staff also reviewed the operating experience provided in the LRA, and interviewed theapplicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.
3-41UFSAR Supplement. In LRA Section A.2.1.35, the applicant provided the UFSAR supplement forthe Water Chemistry Control - BWR Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).In addition, in a letter dated January 4, 2007, the applicant provided a revision to its LRA toexplicitly state the One-Time Inspection Program activities will confirm the effectiveness of the Water Chemistry Control - BWR Program.
Conclusion. On the basis of its audit and review of the applicant's Water Chemistry Control -BWR Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2  AMPs Consistent with the GALL Report with Exceptions and/or EnhancementsIn LRA Appendix B, the applicant stated the following AMPs that are, or will be, consistent withthe GALL Report, with exceptions or enhancements:
* Buried Piping Inspection Program
* BWR Control Rod Drive Return Line Nozzle Program
* BWR Feedwater Nozzle Program
* BWR Penetrations Program
* BWR Stress Corrosion Cracking Program
* BWR Vessel Inside Diameter Attachment Welds Program
* BWR Vessel Internals Program
* Containment Leak Rate Program
* Diesel Fuel Monitoring Program
* Fatigue Monitoring Program
* Fire Protection Program
* Fire Water System Program
* Oil Analysis Program
* Reactor Head Closure Studs Program
* Reactor Vessel Surveillance Program
* Service Water Integrity Program
* Structures Monitoring Program
* Water Chemistry Control - Closed Cooling Water Program
* Bolting Integrity Program
* Metal Enclosed Bus Inspection Program 3-42For AMPs that the applicant claimed are consistent with the GALL Report, with exception(s)and/or enhancement(s), the staff performed an audit and review to confirm that program attributes or features for which the applicant claimed consistency were indeed consistent. Thestaff also reviewed the exception(s) and/or enhancement(s) to the GALL Report to determine whether they were acceptable and adequate. The results of the staff's audits and reviews are documented in the following sections.3.0.3.2.1  Buried Piping Inspection Program Summary of Technical Information in the Application. LRA Section B.1.1 and LRA supplementdated March 23, 2007, describe the existing Buried Piping Inspection Program as consistent, with exceptions and enhancements, with GALL AMP XI.M34, "Buried Piping and Tanks Inspection." This program includes: (a) preventive measures to mitigate corrosion and (b) inspections tomanage the effects of corrosion on the pressure-retaining capability of buried carbon steel, stainless steel, and gray cast iron components. Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. Buried components are inspected when excavated during maintenance. Prior to the period of extended operation, plant operating experience will be reviewed to verify that there had been an inspection within the previous ten years. There will be a focused inspection within the first 10 years of the period of extended operation unless an opportunistic inspection (or an inspection of pipe condition without excavation) occurs within this ten-year period.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exceptions and enhancements to determine whether the AMP, with the exceptions and enhancements, remained adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the Buried Piping Inspection Program for which theapplicant claimed consistency with GALL AMP XI.M34 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's Buried Piping Inspection Program provided assurance that the program will manage aging effects on the external surfaces of buried steel piping. The staff finds the applicant's Buried Piping Inspection Program acceptable because it conformed to the recommended GALL AMP XI.M34, "Buried Piping and Tanks Inspection," with exceptions and an enhancements.Exception 1. In LRA Section B.1.1, the applicant stated an exception to the GALL Reportprogram element "scope of program." Specifically, the exception states that: The GALL Report refers to buried steel piping and tanks. The VYNPS programdoes not inspect tanks. There are no buried steel tanks subject to an AMR.In addition, the applicant stated in the LRA, that preventive measures are taken at VYNPS thatare in accordance with standard industry practices.The staff asked the applicant to describe the tanks at VYNPS. The applicant responded that theonly below-grade tank at VYNPS that is below grade is the diesel fire pump tank, which is in a 3-43vault, so it is not exposed to a soil environment. The only buried tank at VYNPS is the JohnDeere Diesel tank, which is fiberglass. The GALL Report does not identify fiberglass as a material that is subject to an AERM. These tanks are monitored by the Diesel Fuel Monitoring Program.The staff reviewed the applicant's response. The applicant clarified that the only buried tank atVYNPS is fiberglass, which is not subject to the aging mechanisms identified in the GALL Report. On the basis that fiberglass is a material not subject to a loss of material and the tanks are monitored by the applicant's Diesel Fuel Monitoring Program, the staff found this exception acceptable.Exception 2. In LRA Section B.1.1, the applicant stated an exception to the GALL Reportprogram element "detection of aging effects." Specifically, the exception states: Inspections via methods that allow assessment of pipe condition withoutexcavation may be substituted for inspections requiring excavation solely for the purpose of inspection. Methods such as phased array ultrasonic testing (UT) technology provide indication of wall thickness for buried piping without excavation. Use of such methods to identify the effects of aging is preferable to excavation for visual inspection, which could result in damage to coatings or wrappings.The LRA also states that, as an alternative to examination methods that require excavation toexamine buried piping, examination methods that do not require excavation may be substituted.
The LRA identifies phased array UT to determine wall thickness as one such alternative.The staff asked the applicant to provide technical justification of the phased array UTexamination technique and other examination methods that VYNPS planned to perform as an exception. The applicant explained that robotic crawlers that can perform phased array UT examinations are available. These UT examinations can perform piping wall thickness measurements, which provide an indication of the condition of the exterior surface of the piping being examined. While these alternative examination methods are planned to be performed to obviate the need for excavation, in the event that they detect wall thinning sufficient to indicate that the exterior piping surface is corroded or damaged, excavation will be performed in order to better evaluate the exterior surface condition, and to repair or to replace the piping, as needed.
When the staff asked the applicant how buried piping would be examined when it cannot be examined by UT, due to size or material, the applicant responded that excavation and examination would be performed, as normal. On the basis that either UT or excavation will be performed to determine wall thickness of buried piping, the staff finds this exception acceptable.Enhancement 1.
In LRA Section B.1.1, the applicant stated the following enhancement inmeeting the GALL Report program element "parameters monitored/inspected." Specifically, the enhancement stated (Commitment # 1):Guidance for performing examinations of buried piping will be enhanced tospecify that coating degradation and corrosion are attributes to be evaluated.
3-44The applicant further stated, in the LRA, that this program included examinations to detect andmanage the effects of corrosion on the pressure-retaining capability of buried piping.The staff noted that a VYNPS program procedure required "a general visual examination forobvious signs of settlement, joint separation, cracks (concrete pipe), obvious misalignment, etc."
of buried piping. Also, the staff noted that the program procedure was very general rather than focused on coating or wrapping integrity. The staff determines that this procedure did not adequately address the GALL Report recommendation in that the average examiner would not be able to read the procedure requirements and find evidence of age-related damage to piping surfaces or coverings. The applicant will enhance plant procedure 7030 (PP 7030), Structures Monitoring Program Procedures, to provide additional guidelines for the examination of buried piping and underground structures. The enhancements include an improved definition of the scope of buried piping examinations; a requirement to define the condition of the coatings to be examined, including adhesion and discontinuities; a requirement to inspect piping underneathfailed coatings; additional acceptance criteria, including rust and wall thickness; and instructions to notify engineering to perform an opportunistic examination of any buried structure uncovered during the excavation of piping. The staff finds this commitment to be acceptable, since the enhanced procedure will address the recommendations of the GALL Report.On this basis, the staff finds this enhancement acceptable since when the enhancement isimplemented the Buried Piping Inspection Program will be consistent with GALL AMP XI.M34 and will provide additional assurance that the effects of aging will be adequately managed.Enhancement 2. In LRA supplement dated March 23, 2007, the applicant stated the followingenhancement in meeting the GALL Report program element "detection of aging effects."
Specifically, the enhancement stated:Program guidance will be revised to include the following. "A focused inspectionwill be performed within the first 10 years of the period of extended operation, unless an opportunistic inspection (or an inspection via a method that allows an assessment of pipe condition without excavation) occurs within this ten-year period."The staff reviewed the enhancement and its evaluation is documented in the VYNPS - NRCLicense Renewal Inspection Report 05000271/2007006. The staff determined that a focused inspection within the first 10 years of th period of extended operation is acceptable. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented the Buried Piping Inspection Program will be consistent with GALL AMP XI.M34 and will provide additional assurance that the effects of aging will be adequately managed.Operating Experience. LRA Section B.1.1, states that steel piping was excavated and inspectedon several occasions during the past seven years. These inspections revealed no loss of material due to external surface corrosion. Therefore, this operating experience proves that the program manages loss of material caused by corrosion of the external surfaces of buried components.
3-45The applicant stated, during the audit and review, that VYNPS has a comprehensive operatingexperience program that monitors industry events and issues, and assesses them for applicability to its own operations. In addition, VYNPS has a CAP that is used to track, trend, and evaluate significant plant issues and events. Those issues and events, whether from the industry or plant-specific, that are potentially significant to the Buried Piping Inspection Program are evaluated. The Buried Piping Inspection Program is augmented, as appropriate, when these evaluations show that changes to this program will enhance its effectiveness.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. In addition, the staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.1, the applicant provided the UFSAR supplement forthe Buried Piping Inspection Program.In LRA Section A.2.1.1, the applicant stated that its Buried Piping Inspection Programincluded preventive measures to mitigate corrosion and inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel, stainless steel, and graycast iron components. Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. Buried components are inspected when excavated during maintenance. If trending within the CAP identified susceptible locations, the areas with a history of corrosion problems are evaluated for the need for additional inspection, alternate coating, or replacement.A focused inspection will be performed within the first 10 years of the period of extendedoperation, unless an opportunistic inspection (or an inspection via a method that allows an assessment of pipe condition without excavation) occurs within this ten-year period.
(Commitment #44).During the audit and review, the staff asked the applicant to clarify its buried piping examinationplans during the ten-year periods before and during the period of extended operation. The applicant responded to say that buried piping was last examined in 2003, which is within the final ten-year period before the period of extended operation. Therefore, even if no other buried piping is examined until the end of the current operating license, VYNPS has followed staff guidance regarding the examination of buried piping through the end of the current operating license. Regarding the period of extended operation, the applicant stated, in the LRA and the UFSAR, that a focused examination of buried piping will be performed within the first ten years of the period of extended operation, unless an opportunistic examination or an examination byan examination method that allows an assessment of the buried piping surface condition without excavation, occurs within that ten-year period.
3-46The applicant committed (Commitment #1) to enhance guidance for performing examinations ofburied piping to specify that coating degradation and corrosion are attributes to be evaluated for its Buried Piping Program by March 21, 2012.The staff reviewed LRA Section A.2.1.1, and determined that, upon the implementation ofCommitment #1 and Commitment #44, the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Buried Piping InspectionProgram, the staff determines that the AMP, with the exceptions, is adequate to manage the aging effects for which it is credited. Also, the staff reviewed the enhancements (Commitments
#1 and #44) and confirmed that their implementation prior to the period of extended operation would make the existing AMP consistent with the GALL AMP. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.2  BWR CRD Return Line Nozzle Program Summary of Technical Information in the Application. LRA Section B.1.2 describes the existingBWR CRD Return Line Nozzle Program as consistent, with exception, with GALL AMP XI.M6, "BWR Control Rod Drive Return Line Nozzle." In accordance with this program, the applicant has rerouted the CRD return flow to the reactorwater cleanup (RWCU) system with the rerouted line flow valved open and capped the CRD return line vessel nozzle to mitigate cracking. Inservice Inspection (ISI) examinations monitor the effects of crack initiation and growth on the intended function of the CRD return line nozzle and
 
cap.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the BWR CRD Return Line Nozzle Program for which theapplicant claimed consistency with GALL AMP XI.M6 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's BWR CRD Return Line Nozzle Program provides assurance that aging effects within the scope of license renewal are adequately managed. The staff finds the applicant's BWR CRD Return Line Nozzle Program acceptable because it conforms to the recommended GALL AMP XI.M6, "BWR Control Rod Drive Return Line Nozzle," with exceptions.Exception. In LRA Section B.1.2, the applicant stated exception to the GALL Report programelements "parameters monitored/inspected," "detection of aging effects," and "monitoring and trending." Specifically, the exception states:
3-47VYNPS does not inspect the welded connection between the CRD return line andthe RWCU system piping during each refueling outage.The applicant stated that in its SE of BWR FW and CRD return line modifications at VYNPS,NRC accepted VYNPS' commitment to inspect the CRD return line to RWCU joint, by UT methods, for three consecutive refuel outages, then to reassess the inspection frequency based upon the inspection results. Inspection of the three CRD return line to RWCU welds confirmed there were no indications; and the VYNPS assessment concluded that further inspections are not required. The staff reviewed this assessment and determines that it was acceptable.In the LRA, the applicant asserted that is reasonable to maintain this exception for the period ofextended operation since the CRD return line now ties into the RWCU system in a section of piping that is nonsafety-related (no license renewal function) and is not subject to an AMR. The applicant further stated that the BWR CRD Return Line Nozzle Program monitors the effects of cracking on the intended function of the CRD return line nozzle by performing ultrasonic inspection of the nozzle inner radius, nozzle to vessel weld, and nozzle to cap weld in accordance with the American Society of Mechanical Engineers (ASME) Code, Section XI, Subsection IWB.The staff noted that the inspections identified in NUREG-0619, "BWR Feedwater Nozzle andControl Rod Drive Return Line Nozzle Cracking: Resolution of Generic Technical Activity A-10,"
for the rerouted return line are not addressed by the BWR CRD Return Line Program, and this had been appropriately identified as an exception to the referenced GALL Report program.
Considering that the return line welds had been subject to enhanced inspection, that the results had been reviewed by the staff, and that the welds are in a system that is not subject to an AMR, the staff finds this exception to be acceptable.Operating Experience. LRA Section B.1.2 states that the CRD return line nozzle ultrasonicexamination in October 2002 found no indications of cracking.The staff reviewed plant records of the examinations identified in the LRA, and interviewed theapplicant's technical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.2, the applicant provided the UFSAR supplement forthe BWR CRD Return Line Nozzle Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's BWR CRD Return Line NozzleProgram, the staff determines that those program elements for which the applicant claimed 3-48consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptionand its justification and determines that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.3  BWR Feedwater Nozzle Program Summary of Technical Information in the Application. LRA Section B.1.3 describes the existingBWR Feedwater Nozzle Program as consistent, with exception, with GALL AMP XI.M5, "BWR Feedwater Nozzle." In accordance with this program, the applicant has replaced the original low flow control valvewith a drag-type valve with improved flow characteristics, replaced the FW spargers with interference-fit thermal sleeve spargers, and installed a thermal sleeve bypass leak detection system to mitigate cracking. This program continues enhanced ISI of the FW nozzles in accordance with the requirements of ASME Code, Section XI, Subsection IWB and the recommendation of General Electric (GE) NE-523-A71-0594 to monitor the effects of cracking on the intended function of the FW nozzles.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the BWR Feedwater Nozzle Program for which theapplicant claimed consistency with GALL AMP XI.M5 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's BWR Feedwater Nozzle Program provides assurance that aging of the FW nozzles will be adequately managed. The staff finds the applicant's BWR Feedwater Nozzle Program acceptable because it conforms to the recommended GALL AMP XI.M5, "BWR Feedwater Nozzle," with an exception.Exception. In LRA Section B.1.3, the applicant stated an exception to the GALL Report programelement "preventive actions." Specifically, the exception states:Stainless steel cladding was not removed, a low-flow controller was not installedand the RWCU system was not rerouted.The LRA further states that VYNPS performs the enhanced ISI recommended by a GE guidancedocument to monitor the effects of cracking on the intended function of the FW nozzles and has performed system modifications to mitigate cracking.The staff reviewed the applicable portions of the program procedures for VYNPS inserviceinspection and a VYNPS calculation on crack growth for the FW nozzles. In addition, the staff reviewed NVY 84-144, in which the staff provided its SE of BWR FW modifications at VYNPS 3-49and determined that the intent of the requirements of NUREG-0619 and NEDE-21821-A hadbeen satisfied by the modifications performed.The staff finds that FW nozzle cracking continues to be adequately managed by the existingprogram. On this basis, the staff finds this exception to be acceptable.Operating Experience. Section B.1.3, states that inspections following FW system modificationsshow no new cracking of the FW nozzle, indicating that plant modifications to reduce thermal stresses have been effective in resolving the FW nozzle cracking issue. Ultrasonic testing of the FW nozzle in October 2002 resulted in no recordable indications. Absence of recordable indications proves that the program is effective for managing FW nozzle cracking. QA assessments in 2002 and 2004 revealed no issues or findings that could impact program effectiveness.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. Data from the bypass leakage detection system continues to be used appropriately to ensure adequate conservatism in modeling the aging of the interference-fit thermal sleeve.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.3, the applicant provided the UFSAR supplement forthe BWR Feedwater Nozzle Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's BWR Feedwater NozzleProgram, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justifications and determined that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.4  BWR Penetrations Program Summary of Technical Information in the Application. LRA Section B.1.4 describes the existingBWR Penetrations Program as consistent, with exceptions, with GALL AMP XI.M8, "BWR Penetrations."
3-50The program includes: (a) inspection and flaw evaluation conforming to the guidelines ofstaff-approved documents BWRVIP-27 and BWRVIP-49 and (b) monitoring and control of reactor coolant water chemistry in accordance with guidelines to ensure the long-term integrity of vessel penetrations and nozzles.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exceptions to determine whether the AMP, with the exceptions, remained adequate to manage the aging effects for which it is credited.The GALL Report, in the preventive actions program element for GALL AMP XI.M8, stated thatmaintaining high water purity reduces susceptibility to SCC or intergranular stress-corrosion cracking (IGSCC) and reactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29. The applicant stated, in the LRA, that the applicant's reactor water chemistry is monitored and maintained in accordance with the guidelines of BWRVIP-130 to ensure the long-term integrity of vessel penetrations and nozzles.The staff reviewed the Water Chemistry Control-BWR Program and concludes that it isacceptable. The acceptance of the applicant's Water Chemistry Control-BWR Program is addressed in SER Section 3.0.3.1.11.The staff reviewed those portions of the BWR Penetrations Program for which the applicantclaimed consistency with GALL AMP XI.M8 and finds that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's BWR Penetrations Program provided assurance that the applicant's BWR Penetrations Program will adequately manage the aging effects. The staff finds the applicant's BWR Penetrations Program acceptable because it conformed to the recommended GALL AMP XI.M8, "BWR Penetrations," with exceptions.Exception 1. In LRA Section B.1.4, the applicant stated exception to the GALL Report programelements "parameters monitored/inspected" and "detection of aging effects." Specifically, the exception states: Table IWB-2500-1 from the 1998 Edition with 2000 Addenda of ASME Code,Section XI is used to specify SLC nozzle inspections, while the GALL Report specifies the 2001 Edition with 2002 and 2003 Addenda.The applicant further stated, in the LRA, that "Since ASME Code, Section XI through the 2003Addenda has been accepted by reference in 10 CFR 50.55a, paragraph (b)(2), without modification or limitation on use of Table IWB-2500-1 from the 1998 Edition with 2000 Addenda for BWR components, use of this version is appropriate to assure that components crediting this program can perform their intended function consistent with the CLB during the period of extended operation."The staff reviewed inspection requirements and finds that there is no change for the penetrationinspection requirements in IWB-2500 for the ASME Code Edition/Addendum identified in this exception. On this basis, the staff finds this acceptable.
3-51Exception 2. In LRA Section B.1.4, the applicant stated exception to the GALL Report programelement "detection of aging effects." Specifically, the exception states:VYNPS examines 1/2 inch of the volume next to the widest part of the N10 nozzleto vessel weld, rather than half of the vessel wall thickness.The applicant stated, in the LRA, that "Extending the examination volume into the base metal asrequired by ASME Code, Section XI, 1998 Edition, 2000 Addenda, Figure IWB-2500-7(b) prolongs the examination time significantly and results in no net increase in safety. The extra volume is base metal region which is not prone to inservice cracking and has been extensively examined before the vessel was put into service and during the first, second and third interval examinations."The staff asked the applicant to provide additional justification instead of referencingexamination results from previous intervals. The applicant stated the inspection of the vessel penetrations to 1/2 inch versus 1/2 vessel wall thickness was consistent with ASME Code Case N-613-1 which has been endorsed by the NRC as documented in Regulatory Guide 1.147, Revision 14. As the applicant's inspections are consistent with the NRC-approved ASMECode Case N-613-1, the staff finds this exception acceptable.Operating Experience. LRA Section B.1.4 states that enhanced leakage inspection (withinsulation removed) of the SLC nozzle in October 2002 resulted in no recordable indications.
Absence of recordable indications proves that the program is effective for managing SLC nozzle cracking. Liquid penetrant examination of instrument penetration nozzles in May 2001 resulted in no recordable indications. Absence of recordable indications proves that the program is effective for managing instrument penetration nozzle cracking. The applicant, as a participant in the BWRVIP, is committed to incorporate lessons learned from operating experience of the entire BWR fleet. The applicant evaluates BWRVIP inspection criteria and industry operating experience to determine whether the existing program should be modified.The staff reviewed the operating experience provided in the LRA and industry operatingexperience documented in related BWRVIP reports, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation the criterion defined in the GALL Report and in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.4, the applicant provided the UFSAR supplement forthe BWR Penetrations Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-52 Conclusion. On the basis of its audit and review of the applicant's BWR Penetrations Program,the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their justifications and determines that the AMP, with the exceptions, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.5  BWR Stress Corrosion Cracking Program Summary of Technical Information in the Application. LRA Section B.1.5 describes the existingBWR Stress Corrosion Cracking Program as consistent, with exception, with GALL AMP XI.M7, "BWR Stress Corrosion Cracking." The program includes: (a) preventive measures to mitigate IGSCC and (b) inspection and flawevaluation to monitor IGSCC and its effects on RCPB components made of stainless steel, CASS, or nickel alloy.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited.The GALL Report, in the preventive actions program element for GALL AMP XI.M7, stated thatmaintaining high water purity reduces susceptibility to SCC or IGSCC and reactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29. The applicant's reactor water chemistry is monitored and maintained in accordance with the guidelines of BWRVIP-130.The staff reviewed the Water Chemistry Control-BWR Program, and concludes that it isacceptable. The acceptance of the Water Chemistry Control-BWR Program is addressed in SER Section 3.0.3.1.11.The applicant stated, that extensive piping replacement and mitigating treatments were appliedthroughout the austenitic piping system during the decade from 1977 to 1986 and the result of these actions is that nearly all piping, nozzles, and welds in the austenitic system are composed of resistant materials. The staff finds this meets the GALL Report's recommendation.The staff reviewed those portions of the BWR Stress Corrosion Cracking Program for which theapplicant claimed consistency with GALL AMP XI.M7 and finds that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's BWR Stress Corrosion Cracking Program provides assurance that IGSCC will be adequately managed and the intended function of the pressure boundary piping made of susceptible material will be maintained consistent with the CLB for the period of extended operation. The staff finds the applicant's BWR Stress Corrosion Cracking Program acceptable because it conforms to the recommended GALL AMP XI.M7, "BWR Stress Corrosion Cracking," with an exception.
3-53Exception. In LRA Section B.1.5, the applicant stated an exception to the GALL Report programelement "acceptance criteria." Specifically, the exception states:The 1998 Edition with 2000 Addenda of ASME Code, Section XI,Subsection IWB-3600 is used for flaw evaluation, while the GALL Report specifies the 1986 Edition of ASME Code, Section XI, Subsection IWB-3600 for flaw evaluation.The applicant stated, in the LRA, that "Since ASME Section XI through the 2003 Addenda hasbeen accepted by the NRC in 10 CFR 50.55a, paragraph (b)(2), without modification or limitation on use of Subsection IWB-3600 from the 1998 Edition with 2000 Addenda, use of this version for flaw evaluation is appropriate to assure that components crediting this program can perform their intended function consistent with the CLB during the period of extended operation."The staff reviewed the Inservice Inspection Program, and concludes that it is acceptable. Theacceptance of the applicant's Inservice Inspection Program is addressed in SER Section 3.0.3.3.3. ASME Code, Section XI, Subsection IWB-3600 is part of the Inservice Inspection Program. On this basis, the staff finds this exception acceptable.Operating Experience. LRA Section B.1.5 states that liquid penetrant and ultrasonicexaminations of Generic Letter (GL) 88-01 nozzle safe end welds in May 2001 and October 2002 resulted in no recordable indications. Absence of recordable indications on the nozzle safe end welds proves that the program is effective for managing cracking of austenitic stainless steel piping and components. Preventive measures to mitigate cracking, includingreplacement and modification of austenitic piping and components, have been approved by the staff as part of an effective SCC mitigation strategy. QA assessment in 2001 revealed no issues or findings that could impact program effectiveness.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.5, the applicant provided the UFSAR supplement forthe BWR Stress Corrosion Cracking Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's BWR Stress CorrosionCracking Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justifications and determines that the AMP, with the exception, is adequate to 3-54manage the aging effects for which it is credited. The staff concludes that the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.6  BWR Vessel ID Attachment Welds Program Summary of Technical Information in the Application. LRA Section B.1.6 describes the existingBWR Vessel ID Attachment Welds Program as consistent, with exception, with GALL AMP XI.M4, "BWR Vessel ID Attachment Welds." The program includes: (a) inspection and flaw evaluation in accordance with the guidelines ofstaff-approved BWRVIP-48 and (b) monitoring and control of reactor coolant water chemistry in accordance with the guidelines of BWRVIP-130 (EPRI Report 1008192) to ensure the long-term integrity and safe operation of reactor vessel inside diameter (ID) attachment welds and support
 
pads.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited.The GALL Report, in the preventive actions program element for GALL AMP XI.M4, stated thatmaintaining high water purity reduces susceptibility to SCC or IGSCC and reactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29. The applicant stated, in the LRA, that the applicant's reactor water chemistry is monitored and maintained in accordance with the guidelines of BWRVIP-130.The staff reviewed the Water Chemistry Control-BWR Program and concluded that it isacceptable. The acceptance of the applicant's Water Chemistry Control-BWR Program is addressed in Section 3.0.3.1.11 of this SER.BWRVIP-48 requires that steam dry support and feedwater sparger bracket attachment weldswhich use furnace-sensitized stainless steel (E 308/309 or 308L/309L) or Alloy 600 material be examined by modified VT-1 inspection. The staff asked the applicant to clarify the inspection requirements for those attachments. The applicant responded that the program procedure states clearly that these brackets are examined as if they are furnace-sensitized. The staff reviewed the applicable program procedures and determined this position is consistent with the GALL Report's recommendation.The staff reviewed those portions of the BWR Vessel ID Attachment Welds Program for whichthe applicant claimed consistency with GALL AMP XI.M4 and finds that they are consistent with the GALL Report AMP. Furthermore, the staff concludes that the applicant's BWR Vessel ID Attachment Welds Program provides assurance that cracking will be adequately managed and the intended function of the vessel ID attachments will be maintained consistent with the current licensing basis for the period of extended operation. The staff found the applicant's BWR Vessel 3-55ID Attachment Welds Program acceptable because it conforms to the recommended GALLAMP XI.M4, "BWR Vessel ID Attachment Welds," with an exception.Exception. In LRA Section B.1.6, the applicant stated an exception to the GALL Report programelement "parameters monitored/inspected." Specifically, the exception states:Table IWB-2500-1 from the 1998 Edition with 2000 Addenda of ASME Section XIis used, while the GALL Report specifies the 2001 Edition with 2002 and 2003
 
Addenda.The applicant further stated, in the LRA, that "Since ASME Section XI through the 2003Addenda has been accepted by reference in 10 CFR 50.55a paragraph (b)(2) without modification or limitation on use of Table IWB-2500-1 from the 1998 Edition with 2000 Addenda for BWR components, use of this version is appropriate to assure that components crediting this program can perform their intended function consistent with the current licensing basis during the period of extended operation."The staff reviewed the Inservice Inspection Program and concluded that it is acceptable. Theacceptance of the applicant's Inservice Inspection Program is addressed in Section 3.0.3.3.3 of this SER. On this basis, the staff found this exception acceptable.Operating Experience. LRA Section B.1.6 states that visual inspections of vessel ID attachmentwelds in October 2002 recorded no indications. Absence of recordable indications proves that the program is effective for managing cracking of vessel attachment welds. Staff inspections in 2002 and 2004 and a self-assessment in 2002 revealed no issues or findings that could impact program effectiveness.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.6, the applicant provided the UFSAR supplement forthe BWR Vessel ID Attachment Welds Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's BWR Vessel ID AttachmentWelds Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justifications and determines that the AMP, with the exception, is adequate to 3-56manage the aging effects for which it is credited. The staff concludes that the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.7  BWR Vessel Internals Program Summary of Technical Information in the Application. LRA Section B.1.7 describes the existingBWR Vessel Internals Program as consistent, with exceptions and enhancement, with GALL AMP XI.M9, "BWR Vessel Internals." The program includes (a) inspection, flaw evaluation, and repair in conformance with applicable,staff-approved, BWRVIP documents and (b) monitoring and control of reactor coolant water chemistry in accordance with the guidelines of BWRVIP-130 to ensure the long-term integrity of vessel internal components.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exceptions and enhancement to determine whether the AMP, with the exceptions and enhancement, remained adequate to manage the aging effects for which it is credited.The staff noted that the BWR Vessel Internals Program was credited to manage the steam dryerin LRA Section 3.1. The staff noted that the BWR Vessel Internals Program does not address steam dryer in the AMP and asked the applicant to address this item. In a letter dated August 22, 2006, the applicant committed (Commitment #37) to continue inspections in accordance with the VYNPS steam dryer monitoring plan, Revision 3. These inspections incorporate the guidelines of GE-SIL-644, Revision 1 in accordance with existing procedures.
The applicant will evaluate BWRVIP-139 upon approval by the staff and either include its recommendations in the BWR Vessel Internals Program or inform the staff of exceptions to that document.The GALL Report, in the preventive actions program element for GALL AMP XI.M7, stated thatmaintaining high water purity reduces susceptibility to SCC or IGSCC and reactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29 (EPRI TR-103515). The applicant's reactor water chemistry is monitored and maintained in accordance with the guidelines of BWRVIP-130.The staff reviewed the Water Chemistry Control-BWR Program, and concludes that it isacceptable. The acceptance of the applicant's Water Chemistry Control Program is addressed in SER Section 3.0.3.1.11. On this basis, the staff finds this difference acceptable.The staff reviewed those portions of the BWR Vessel Internals Program for which the applicantclaimed consistency with GALL AMP XI.M9 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's BWR Vessel Internals Program 3-57provided assurance that aging effects for vessel internals will be managed so that the systemsand components within the scope of this program will continue to perform their intended functions consistent with the CLB through the period of extended operation. The staff finds the applicant's BWR Vessel Internals Program acceptable because it conformed to the recommended GALL AMP XI.M9, "BWR Vessel Internals," with the exceptions and enhancement.Exception 1
. In LRA Section B.1.7, the applicant stated an exception to the GALL Reportprogram elements "scope of program" and "detection of aging effects." Specifically, the exception states:Core Shroud - For shroud horizontal welds H1, H2 and H3, VYNPS inspects 18inches in length in each of the four quadrants from the outside diameter using EVT-1 methods. If cracks are found in a quadrant, the length is expanded in that quadrant to detect 18 inches of unflawed weld. Thus, VYNPS does not meet the BWRVIP-76 requirement to inspect both the outside and inside diameter of the welds and does not meet the requirement to inspect 100 percent of the length of the welds.Exception Note: The applicant stated, in the LRA, that "The CS spargers cover H1and H2, and grating covers the periphery of the top guide. Therefore, access to the shroud inside diameter would be through vacated fuel cells, which would result in the camera being too distant from the inspection surfaces to perform an adequate EVT-1 of H1, H2, or H3. Although no BWRVIP guidance is given for one-sided visual examinations of horizontal welds, they are inspected on a six-year frequency following the BWRVIP guidance for a one-sided EVT-1 of vertical welds. The excellent results obtained in the 1995 ultrasonic examination of welds H1, H2, and H3 (very limited indications) and the 1996 ultrasonic examination of the vertical and ring segment welds (no indications) provide additional assurance that a one sided EVT-1 is acceptable."The staff noted that the proposed outside diameter inspection cannot detect cracks initiated fromthe inside diameter and industry operating experience indicated that cracks have been initiated from the inside diameter. The applicant responded that one-sided EVT-1 will not be used and will follow BWRVIP-76's recommendation.In a letter dated January 4, 2007, the applicant provided an amendment to its LRA to delete theexception related to the core shroud. Specifically, the applicant revised the BWR Vessel Internals Program as follows:1. Delete the exception to the BWR Vessel Internal Program related to the coreshroud (page B-27)2. Delete exception Note #1 on page B-29.On the basis that this exception is deleted and the applicant will follow BWRVIP-76'srecommendation, consistent with the GALL Report recommendation, the staff finds this acceptable.
3-58Exception 2. In LRA Section B.1.7, the applicant stated exception to the GALL Report programelements "scope of program" and "detection of aging effects." Specifically, the exception states that:Core Plate - VYNPS performs VT-3 inspection of 50 percent (15) of the top of thecore plate rim hold-down bolts every other refueling outage. If access to the lower plenum becomes available, VYNPS plans to perform a VT-3 inspection of accessible rim hold-down bolt bottom locking engagement and accessible aligner pin assemblies. Thus, VYNPS does not meet the BWRVIP-25 requirement to perform enhanced VT-1 from below the core plate of 50 percent of the hold-down bolts.The applicant also stated that "A baseline VT-3 examination of the tops of all 30 boltedconnections was performed in 1996. Followup VT-3 examinations of tops of 50 percent of the bolted connections were performed in 1999, 2000 and 2001. None of the exams found evidence of cracking or bolting disassembly. Since the lower bolted connections are similar to the top, and there are no failed connections in the sample that is inspected, it is unlikely that a significant number of failed connections could exist in the remainder of the population. Therefore, the VYNPS inspection plan is adequate for ensuring the structural integrity of the core plate configuration to resist sliding against shear loads."The staff noted that VT-3 cannot detect cracking and asked the applicant for further justification.The staff also asked the applicant to provide the plant-specific TLAA analysis as identified in the applicant's action item of BWRVIP-25. The applicant responded that there is no TLAA to support an inspection sample of 50 percent of the bolts with none cracked to assure the integrity of a critical number of bolts.In a letter dated July 6, 2006, the applicant provided Commitment #2 and Commitment #29 toaddress this exception. In this letter, the applicant stated that VYNPS will either install core plate wedge or complete a plant-specific analysis to determine acceptance criteria for continued inspection for core plate hold down bolting in accordance with BWRVIP-25.Since the applicant committed to either install a core plate wedge or complete a plant-specificanalysis to determine acceptance criteria for continued inspection for core plate hold down bolting in accordance with BWRVIP-25, the staff finds this exception acceptable.Exception 3. In LRA Section B.1.7, the applicant stated an exception to the GALL Reportprogram elements "scope of program" and "detection of aging effects." Specifically, the exception states that:Core Spray - VYNPS defers inspection of the three inaccessible welds insideeach of the two CS nozzles, and the P9 welds inside the CS shroud collars, until a delivery system for ultrasonic testing of the hidden welds is developed. Thus, VYNPS does not meet the BWRVIP-18 requirement to perform an ultrasonic inspection of a full target weld set every other refueling outage.
3-59The applicant stated, in the LRA, that "The three CS thermal sleeve welds in each of the two CSnozzles are full penetration butt welds, which decreases the likelihood of cracking. Inspections of similar CS piping welds, such as junction box-to-pipe and upper elbow welds, showed no indication of cracking. Integrity of the P9 welds must be considered because indications have been recorded during ultrasonic examination of collar-to-shroud welds at VYNPS. The P9 welds are creviced. All other creviced CS welds at VYNPS - the junction box cover plate welds, P1 welds and downcomer sleeve welds - show no indications of cracking. Therefore, deferral of inspection of the inaccessible welds is justified."
The staff noted that BWRVIP-18 states that inspection technique development needed for the inaccessible (thermal sleeve) welds is being addressed by the BWRVIP inspection committee as a high priority item (since 1996). The staff asked the applicant to provide justification to address this exception. In a letter dated July 6, 2006, the applicant provided Commitment #36 to address this item. Inthis letter, the applicant stated that "If technology to inspect the hidden jet pump thermal sleeve and CS thermal sleeve welds has not been developed and approved by the NRC at least two years prior to the period of extended operation, VYNPS will initiate a plant-specific action to resolve this issue. That plant-specific action may be justification that the welds do not require inspection." The staff finds this commitment to be acceptable, since the enhanced procedure will address the recommendations of the GALL Report. On the basis of this commitment, the staff finds this exception acceptable.Exception 4. In the LRA Section B.1.7, the applicant stated an exception to the GALL Reportprogram elements "scope of program" and "detection of aging effects." Specifically, the exception states that:Jet Pump Assembly - VYNPS uses EVT-1 inspection of six jet pump weldswith UT indications. Thus, VYNPS does not meet guidance implied in BWRVIP-41 that when flaws are identified, subsequent examinations should use the same technique that originally found the flaw. VYNPS defers inspection of jet pump inaccessible welds, until a delivery systemfor ultrasonic testing of the hidden welds is developed. Thus, VYNPS does not meet the BWRVIP-41 requirement to perform a modified VT-1 of 100 percent of these welds over two 6-year inspection cycles and 25 percent per inspection cycle thereafter.The applicant noted that: "The hidden jet pump welds are far enough into the nozzle that failure at thesewelds would not result in the thermal sleeve disengaging from the nozzle before the riser contacted the shroud. If the jet pump thermal sleeve or riser piping severed, it would be detected through jet pump monitoring, which alarms if the riser pipe moves more than 10 percent while at or above a core flow of 42 Mlb/hr.
Therefore, deferral of inspection of the inaccessible welds is justified.
3-60For jet pump welds, BWRVIP-41 finds EVT-1 or UT to be acceptable examinationtechniques. In 1996, VYNPS performed UT examinations and recorded indications in six jet pump welds. All six welds were reinspected by UT after two cycles of operation and there were no new indications or growth of existing indications. Since the reinspection demonstrated that there is no active cracking in these welds, and EVT-1 inspection will reveal cracking prior to encroachment on the weld structural integrity limit, performing subsequent inspections using the EVT-1 technique is acceptable. VYNPS will perform the EVT-1 inspections every two cycles until three successive inspections confirm no new indications or growth of existing indications, at which time VYNPS will revert to the six-year inspection interval specified in BWRVIP-41.The staff noted that the SER for BWRVIP-41 states that an AMR of the nozzle thermal sleeve(jet pump inaccessible welds) will be provided by individual applicants and asked the applicant to provide plant-specific justification/commitment to demonstrate that the weld will be adequately managed during the period of extend operation.In a letter dated July 6, 2006, the applicant provided Commitment #36 to address this item. Inthis letter, the applicant stated that "If technology to inspect the hidden jet pump thermal sleeve and CS thermal sleeve welds has not been developed and approved by the NRC at least two years prior to the period of extended operation, VYNPS will initiate plant-specific action to resolve this issue. That plant-specific action may be justification that the welds do not require inspection." The staff finds this commitment to be acceptable, since the enhanced procedure will address the recommendations of the GALL Report. On the basis of this commitment, the staff finds this exception acceptable.The staff also noted that EVT-1 inspection cannot detect the depth of the flaw and there is noway to identify the flaw propagation with EVT-1. The staff asked the applicant to provide further justification for using EVT-1 technique.The applicant gave three reasons why there was no change in the size of the indications. Thefirst was that the indications are not relevant and are caused by either geometry, transducer lift off or are related to metallurgical interfaces, which it states is unlikely. The second possibility isthat the indications are fabrication flaws. The applicant thinks that the fabrication flaws would not have been identified since all that is required during fabrication was a PT exam. The third possibility is that the cracks are IGSCC but, the cracks are not growing.The applicant stated that the BWRVIP has stated that EVT-1 and UT are equivalent. The staffhas accepted this position. The applicant also stated that before integrity of the welds was compromised, the EVT-1 examinations would be able to identify the flaws because they would be long, through-wall circumferential flaws. Furthermore, the applicant stated that flaw propagation can be confirmed through three successive examinations which is consistent with the rules in ASME Code Section XI. Finally, the applicant stated that, in addition to the above reasons, VYNPS Technical Specifications (TS) require that jet pump integrity and operability be checked daily. The staff finds that reverting to the six -year inspection frequency using the EVT-1 technique is acceptable. On this basis, the staff finds this exception acceptable.
3-61Exception 5
. In LRA Section B.1.7, the applicant stated an exception to the GALL Reportprogram elements "scope of program" and "detection of aging effects." Specifically, the exception states that:Control Rod Drive Housing - VYNPS performed less than 5 percent of the CRDguide tube weld exams within the first six-year interval. Thus, VYNPS does not meet the BWRVIP-47 requirement to inspect 5 percent of the CRD guide tube welds within the first six years.The applicant stated, in the LRA, that "To meet the BWRVIP-47 requirement to inspect5 percent of the CRD guide tube welds within the first six years, VYNPS would have to inspect five guide tubes. Four CRD guide tube assemblies were inspected during the first six-year period, for a total of 4.5 percent of the welds. The inspections began in RFO 22 (2001), when four guide tube assemblies were inspected, and were expected to be completed during RFO 23 (2002). Control blade change-out allows access to the interior of the CRD guide tube and, typically, there are between three and ten blade change-outs each outage. However, no control blades were changed during RFO 23. Inspecting one guide tube during RFO 23 to attain the five percent sample level would have required vacating an additional fuel cell (more fuel moves) and an added three hours for disassembly and reassembly (not counting inspection time). This hardship is not justified in terms of safety in order to raise the inspection sample from 4.5 percent to 5 percent. The BWRVIP-47 requirement to inspect 10 percent of the CRD guide tubes over the first twelve years will be met."The staff noted that the program basis document indicated VT-3 inspections were performedand asked the applicant to clarify whether EVT-1 inspection was performed to meet the baseline inspection requirements. The applicant responded that the EVT-1 inspections are conducted on control rod guide tube (CRGT)-2 and CRGT-3 in accordance with BWRVIP-47.On the basis that the inspection meets the BWRVIP-47 guidelines of 10 percent of the CRGTover the 12 years, the staff finds this exception acceptable.Exception 6. In LRA Section B.1.7, the applicant stated an exception to the GALL Reportprogram element "parameters monitored/inspected." Specifically, the exception states that:Table IWB-2500-1 from the 1998 Edition with 2000 Addenda of ASME Code,Section XI is used, while the GALL Report specifies the 2001 Edition with 2002
 
and 2003 Addenda.The applicant stated, in the LRA, that "Since ASME Code, Section XI through the 2003 Addendahas been accepted by reference in 10 CFR 50.55a, paragraph (b)(2), without modification or limitation on use of Table IWB-2500-1 from the 1998 Edition with 2000 Addenda for BWR components, use of this version is appropriate to assure that components crediting this program can perform their intended function consistent with the CLB during the period of extended operation."
3-62The staff reviewed the Inservice Inspection Program and concludes that it is acceptable. Theacceptance of the applicant's Inservice Inspection Program is addressed in SER Section 3.0.3.3.3. ASME Code, Section XI, Subsection IWB-2500 from the 1998 Edition with 2000 Addenda is part of the Inservice Inspection Program. On this basis, the staff finds this exception acceptable.Enhancement. In LRA Section B.1.7, the applicant stated the following enhancement in meetingthe program element "scope of program." Specifically, the enhancement states:The VYNPS top guide fluence is projected to exceed the threshold forirradiation-assisted stress corrosion cracking (IASCC) (5x10 20 n/cm 2) prior to theperiod of extended operation. Therefore, 10 percent of the top guide locations will be inspected using enhanced visual inspection technique, EVT-1, within the first 12 years of the period of extended operation, with one-half of the inspections (50 percent of locations) to be completed within the first six years of the period of extended operation. Locations selected for examination will be areas that have exceeded the neutron fluence threshold.During the audit and review, the staff noted that the applicant's enhancement addresses the first12 years of the period of extended operation and does not address the remaining period of extended operation. The staff asked the applicant to clarify the reinspection requirement. In a letter dated July 6, 2006, the applicant provided its LRA amendment to address this issue. In its letter, the applicant stated that an inspection requirement will be applied to the remaining period of extended operation.On this basis, the staff finds this enhancement acceptable since when the enhancement isimplemented, the BWR Vessel Internals Program will be consistent with GALL AMP XI.M9 and will provide additional assurance that the effects of aging will be adequately managed.Operating Experience. LRA Section B.1.7 states that cracking of jet pump riser welding (RS-1)was detected during 1998 inspections. Subsequent inspections detected no new indications or growth of existing indications. Potential CS piping weld flaws also were detected during ultrasonic examination in 2001. Indications evaluated in accordance with BWRVIP-18 evaluationcriteria were found acceptable. This operating experience shows that the program is effective at managing the effects of component cracking on the intended function. Visual inspections of reactor vessel internals in 2004 detected no new age-related indications. Absence of new indications shows that the program is effective at managing component aging effects on intended function. Staff inspections, self-assessments, QA audits, and evaluations of industry operating experience from 1999 through 2004 revealed no issues or findings that could impact program effectiveness.The staff's review of plant-specific operating experience revealed conditions discovered by BWRVessel Internals Program examinations similar to those identified elsewhere in the BWR fleet. In each case, indications were evaluated and either found acceptable for further service or appropriately repaired. The BWR Vessel Internals Program is continually adjusted to account for industry experience and research. The staff finds this acceptable.
3-63The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.7, the applicant provided the UFSAR supplement forthe BWR Vessel Internals Program.The applicant committed (Commitment #37) to continue inspections in accordance with thesteam dryer monitoring plan, Revision 3, in the event that the BWRVIP-139 is not approved prior to the period of extended operation; by March 21, 2012.The applicant also committed (Commitment #29), by March 21, 2012, to perform one of thefollowing:1.Install core plate wedges, or, 2.Complete a plant-specific analysis to determine acceptance criteria for continuedinspection of core plate holddown bolting in accordance with BWRVIP-25 and submit the inspection plan to the NRC two years prior to the period of extended operation for NRC review and approval. The applicant made a commitment (Commitment #36) that by March 12, 2012, if technology toinspect the hidden jet pump thermal sleeve and CS thermal sleeve welds has not been developed and approved by the NRC at least two years prior to the period of extended operation, VYNPS will initiate plant-specific action to resolve this issue. That plant-specific actionmay be justification that the welds do not require inspection.The applicant committed (Commitment #2), to inspect 15 percent of the top guide locationsusing enhanced visual inspection technique, EVT-1, within the first 18 years of the period of extended operation, with at least one-third of the inspections to be completed within the first 6 years and at least two-thirds within the first 12 years of the period of extended operation.
Locations selected for the examination will be areas that have exceeded the neutron fluence threshold.The staff reviewed LRA Section A.2.1.7 and determines that, upon the implementation ofCommitments #2, #29, #36 and #37, the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d).
3-64 Conclusion. On the basis of its audit and review of the applicant's BWR Vessel InternalsProgram, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent with the addition of Commitments #2, #29, #36 and #37. In addition, the staff reviewed the exceptions and their justifications and determines that the AMP, with the exceptions, is adequate to manage the aging effects for which it is credited. Also, the staff reviewed the enhancement and confirmed that their implementation prior to the period of extended operation would make the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.8  Containment Leak Rate Program Summary of Technical Information in the Application. LRA Section B.1.8 and LRA supplementdated March 23, 2007, describe the existing Containment Leak Rate Program as consistent, with exceptions, with GALL AMP XI.S4, "10 CFR 50, Appendix J." Containment leak rate tests are required for assurance that: (a) leakage through the primaryreactor containment and systems and components penetrating primary containment does not exceed allowable limits in technical specifications or associated bases and (b) periodic surveillance of reactor containment penetrations and isolation valves is performed so that proper maintenance and repairs are made during the service life of the primary containment and penetrating systems and components.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exceptions, remained adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the Containment Leak Rate Program for which the applicantclaimed consistency with GALL AMP XI.S4 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's Containment Leak Rate Program provided assurance that aging management and other deterioration of the containment leakage limiting boundary is appropriately managed to ensure that postulated post-accident releases are limited to an acceptable level during the period of extended operation. The staff finds the applicant's Containment Leak Rate Program acceptable because it conformed to the recommended GALL AMP XI.S4, "10 CFR 50, Appendix J," with exceptions.Exception 1. In LRA Section B.1.8, the applicant stated an exception to the GALL Reportprogram element "monitoring and trending." Specifically, the exception states:The first Type A test after the April 1995 Type A test shall be performed no laterthan April 2010. This is a one-time extension of the NEI 94-01, 10-year Type A test interval to 15 years. NRC approved Amendment 227 to Facility Operating License DPR-28 for VYNPS to extend the primary containment integrated leak rate testing interval from 10 years to no longer than 15 years on a one-time basis.
3-65The staff reviewed Amendment 227 to Facility Operating License DPR-28 for VYNPS, whichextends the primary containment integrated leak rate testing interval from 10 years to no longer than 15 years. The staff determines that this one-time extension to the current operating license does not cover all subsequent Type A tests which must be performed at ten -year intervals. On this basis, the staff finds this exception acceptable.Exception 2. In the supplement to LRA Section B.1.8, the applicant stated an exception to theGALL Report program element "acceptance criteria." Specifically, the exception states:Main steam leakage pathway contributions (leakage through all four main steamlines and the main steam drain line) are excluded from the overall integrated leakage rate Type A test measurement and from the sum of the leakage rates from Type b and Type c tests.The applicant also stated that the NRC approved Amendment 223 to Facility Operating licenseDPR-28 allowing this exemption from the requirements of Sections III.A and III.B of 10 CFR 50appendix J, Option B because a separate radiological consequence term has been provided for these pathways. The revised design basis radiological consequences analyses address leakage through these pathways as individual factors, exclusive of the primary containment leakage.The staff reviewed the exception and its evaluation is documented in the VYNPS - NRC LicenseRenewal Inspection Report 05000271/2007006. The staff determines that the requirements of Amendment 223 are being followed with the exception, On this basis, the staff finds the exception acceptable. Operating Experience. LRA Section B.1.8 states that during the most recent integrated leakagetesting of primary containment, as-found and as-left test data met all applicable acceptance criteria, indicating that the program is effective at managing the effects of loss of material and cracking on primary containment components. A QA audit in 2001 revealed latent noncompliance with station administrative and requirements of 10 CFR Part 50, Appendix J. An administrative procedure noncompliance created the potential for untimely review of industry operating experience relative to the program. These issues could impact program effectiveness.
However, actions to preclude recurrence of the identified conditions were implemented in accordance with the CAP and subsequent QA audits, QA surveillances, and engineering program health assessments (2003 and 2004) revealed no issues or findings that could impact program effectiveness.During the audit and review, the applicant stated that VYNPS has a comprehensive operatingexperience program that monitors industry events and issues, and assesses them for applicability to its own operations. In addition, VYNPS has a CAP that is used to track, to trend, and to evaluate significant plant issues and events. Those issues and events, whether industry or plant-specific, that are potentially significant to the Containment Leak Rate Program at VYNPS are evaluated. The Containment Leak Rate Program is augmented, as appropriate, when these evaluations show that changes to this program will enhance its effectiveness.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures 3-66internal and external plant operating experience issues, will ensure that operating experience isreviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.8, the applicant provided the UFSAR supplement forthe Containment Leak Rate Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Containment Leak RateProgram, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justifications and determines that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.9  Diesel Fuel Monitoring Program Summary of Technical Information in the Application. LRA Section B.1.9 and LRA supplementdated March 23, 2007, describe the existing Diesel Fuel Monitoring Program as consistent, with exceptions and enhancements, with GALL AMP XI.M30, "Fuel Oil Chemistry." The program samples diesel fuel to maintain adequate quality to prevent corrosion of fuelsystems. Exposure to such fuel oil contaminants as water and microbiological organisms is minimized by periodic draining and cleaning of selected tanks and by verifying the quality of new oil before its introduction into storage tanks. Sampling and analysis activities are in accordance with technical specifications on fuel oil purity and the guidelines of American Society for Testing and Materials (ASTM) Standards D4057-88 and D975-02 (or later revisions of these standards).
Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exceptions and enhancements to determine whether the AMP, with the exceptions and enhancements, remained adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the Diesel Fuel Monitoring Program for which the applicantclaimed consistency with GALL AMP XI.M30 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's Diesel Fuel Monitoring Program provided assurance that the loss of material due to corrosion is adequately managed by monitoring and controlling conditions that would cause this aging effect and by monitoring the effectiveness of the program through surveillance and testing. The staff finds the applicant's 3-67Diesel Fuel Monitoring Program acceptable because it conformed to the recommended GALLAMP XI.M30, "Fuel Oil Chemistry," with exceptions and enhancements.Exception 1. In LRA Section B.1.9, the applicant stated an exception to the GALL Reportprogram elements "scope of program" and "acceptance criteria." Specifically, the exception states:The guidelines of ASTM Standard D6217 are not used along with those of D2276for determination of particulates.The applicant also stated, in the LRA, that the program uses only the guidance providedin ASTM D2276 for the determination of particulates and not both ASTM D2276 and ASTM D6217. In the LRA, the applicant further stated that the use of ASTM D2276 is consistent with the guidance provided in ASTM D975 which is specified in the VYNPS technicalspecifications.The staff finds that the applicant is using one of the methods (ASTM D2276) which isrecommended by the GALL Report. During the audit and review, the applicant stated that the ASTM D6217 provides guidance on determining particulate contamination by sample filtration at an offsite laboratory. However, the use of ASTM D2276 provides for guidance on determining particulate contamination using a field monitor which provides for rapid assessment of changes in contamination. In addition, the applicant stated that the acceptance criteria for ASTM D2276 is more stringent than for ASTM D6217, namely 10 mg/ml versus 24 mg/ml. The staff finds the use of only ASTM D2276 to be conservative.The staff finds this exception acceptable based on using the more stringent of the ASTMstandards recommended by the GALL Report with the added advantage of the quick assessment of contamination changes.Exception 2. In LRA Section B.1.9, the applicant stated exception to the GALL Report programelement "preventive actions." Specifically, the exception states:No additives are used beyond what the refiner adds during production.The applicant also stated, in the LRA, that VYNPS does not add biocides, stabilizers, orcorrosion inhibitors to the diesel fuel. Plant-specific operating experience has not indicatedsignificant problems related to microbiologically-influenced corrosion. Since water contaminationin the diesel fuel storage tanks is minimized, the potential for MIC is limited.The applicant stated that for the past 10 years VYNPS has been buying high quality fuel oil fromthe same supplier. The diesel fuel is tested before delivery and then the diesel fuel in the storage tank is tested monthly. There have been no indications of diesel fuel deterioration or the presence of water or sediment. Since mold and bacteria grow in the water fuel oil interface, the applicant stated during the audit and review that based on the test results there is no need to add biocides. The staff reviewed the operating experience and sample results, and determines that MIC andbreakdown of the diesel fuel have not been issues that necessitated the use of fuel additives.
3-68Furthermore, the Diesel Fuel Monitoring Program provides for routine monitoring of the dieselfuel through monthly surveillance and trending which ensures that the presence of contamination will not go undetected. On this basis, the staff finds this exception acceptable.Exception 3
. In LRA Section B.1.9, the applicant stated exception to the GALL Report programelements "parameters monitored/inspected" and "acceptance criteria." Specifically, the exception states:Only ASTM Standard D1796 is used for determination of water and sediment,rather than Standards D1796 and D2709.The applicant also stated, in the LRA, that ASTM Standards D1796 and D2709 are used fordetermination of water and sediment. However, these standards describe the determination of water and sediment for oils with different viscosities. Either standard is applicable to the #2 diesel fuel oil used at VYNPS. VYNPS uses ASTM Standard D1796 for determination of water and sediment.The GALL Report recommends both ASTM Standards D1796 and D2709 for determining thewater and sediment contamination in diesel fuel. Both of these standards are applicable to the diesel fuel used at VYNPS. The ASTM Standard D1796 is the method referenced in ASTM D975 which VYNPS is using in the plant technical specifications. Since either standard would beappropriate for the VYNPS diesel fuel, the staff accepted the use of ASTM D1796 to determine the water and sediment in the diesel fuel. On this basis, the staff finds this exception acceptable.Exception 4. In LRA Section B.1.9, the applicant stated an exception to the GALL Reportprogram elements "parameters monitored/inspected" and "acceptance criteria." Specifically, the exception states:Determination of particulates may be according to ASTM Standard D2276, ratherthan modified ASTM D2276 Method A.The applicant also stated, in the LRA, that the determination of particulates is based onASTM D2276 and not the modified Method A version of D2276. The VYNPS determination of the presence of unacceptable levels of particulates is based on using a filter with a pore size of 0.8 &#xb5;m which is recommended in ASTM D2276. The modified Method A version of ASTM D2276 uses a filter pore size of 3.0 &#xb5;m.The staff determines that the use of a filter size of 0.8 &#xb5;m instead of 3.0 &#xb5;m when monitoring thepresence of particulates in the diesel fuel is judged to be conservative. Based on the use of the conservative filter pore size, the staff finds the testing provides results that are equivalent or superior to those obtained using a 3.0 &#xb5;m pore size as recommended in the GALL Report. On this basis, the staff finds this exception acceptable.Enhancement 1. In the supplement to LRA Section B.1.9, the applicant stated the followingenhancement in meeting the program element "detection of aging effects." Specifically, the enhancement states:
3-69Ultrasonic thickness measurement of the fuel oil storage and fire pump dieselstorage (day) tank bottom surfaces will be performed every 10 years during tank cleaning and inspection.The staff determines that the monthly testing of the diesel fuel quality and for the presence ofwater and sediment augmented by the ultrasonic thickness measurement of the diesel fuel storage tank bottom every 10 years when the tank is cleaned and inspected will ensure that significant degradation of the tank bottom surface will not go undetected.On this basis, the staff finds this enhancement acceptable since when the enhancement isimplemented, "Diesel Fuel Monitoring Program," will be consistent with GALL AMP XI.M30 and will provide additional assurance that the effects of aging will be adequately managed.Enhancement 2. In the supplement to LRA Section B.1.9, the applicant stated the followingenhancement in meeting the program element "acceptance criteria." Specifically, the enhancement stated:UT measurements of fuel oil storage and fire pump diesel storage (day) tankbottom surfaces will have acceptance criterion  60 percent Tnom. The applicant also stated, in the LRA, that for the ultrasonic measurements of the diesel fuelstorage tank bottom thickness an acceptance criteria of 60 percent of the nominal thickness will
 
be used.The GALL Report does not provide an acceptance criterion for the bottom surface thickness ofthe diesel fuel storage tank. The fuel oil tank is not pressurized so the staff judged the use of 60 percent of the nominal wall thickness provides sufficient margin to be an acceptable criterion for the ultrasonic thickness measurements. The use of this acceptance criterion will provide additional assurance that the effects of aging will be detected before the loss of intended function.On this basis, the staff finds this enhancement acceptable since when the enhancement isimplemented, "Diesel Fuel Monitoring Program," will be consistent with GALL AMP XI.M30 and will provide additional assurance that the effects of aging will be adequately managed.Enhancement 3. In the supplement to LRA Section B.1.9, the applicant stated the followingenhancement in meeting the program element "parameters monitored/inspected." Specifically, the enhancement stated:Fuel oil in the fire pump diesel storage (day) tank will be analyzed according toASTM D975-02 and for particulates per ASTM D2276.The staff reviewed the enhancement and its evaluation is documented in the VYNPS - NRCLicense Renewal Inspection Report 05000271/2007006. The staff determines that performing periodic fuel oil sampling and analysis in accordance with the guidelines of the ASTM Standards is acceptable. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented, "Diesel Fuel Monitoring Program," will be consistent with 3-70GALL AMP XI.M30 and will provide additional assurance that the effects of aging will beadequately managed.Enhancement 4. In the supplement to LRA Section B.1.9, the applicant stated the followingenhancement in meeting the program element "parameters monitored/inspected." Specifically, the enhancement stated:Fuel oil in the john Deere diesel storage tank will be analyzed for particulates perASTM D2276.The staff reviewed the enhancement and its evaluation is documented in the VYNPS - NRCLicense Renewal Inspection Report 05000271/2007006. The staff determines that performing periodic fuel oil sampling and analysis in accordance with the guidelines of the ASTM Standards is acceptable. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented, "Diesel Fuel Monitoring Program," will be consistent with GALL AMP XI.M30 and will provide additional assurance that the effects of aging will be adequately managed.Enhancement 5. In the supplement to LRA Section B.1.9, the applicant stated the followingenhancement in meeting the program element "parameters monitored/inspected." Specifically, the enhancement stated:Fuel oil in the common portable fuel oil storage tank will be analyzed according toASTM D975-02, per ASTM D2276 for particulates, and ASTM D1796 for water and sediment.The staff reviewed the enhancement and its evaluation is documented in the VYNPS - NRCLicense Renewal Inspection Report 05000271/2007006. The staff determines that performing periodic fuel oil sampling and analysis in accordance with the guidelines of the ASTM Standards is acceptable. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented, "Diesel Fuel Monitoring Program," will be consistent with GALL AMP XI.M30 and will provide additional assurance that the effects of aging will be adequately managed.Operating Experience. LRA Section B.1.9 states that fuel oil sampling results from 2000, 2001,2002, and 2003 reveal fuel oil quality maintained in compliance with acceptance criteria. A 1996 visual inspection of the fuel oil storage tank internals revealed no degradation. A 1996 ultrasonic thickness measurement of the tank bottom surface also revealed no significant degradation.
Continuous confirmation of diesel fuel quality and absence of degradation in the fuel oil storagetank prove that the program is effective in preventing loss of material and cracking of fuel system components. QA surveillance in 1999 found an issue that could impact program effectiveness. However, corrective action was taken to update the program to the 2002 version of ASTM D975. There have been no other significant findings.The staff reviewed a sample of the monthly diesel fuel test data from the data highlighted in theLRA. The staff confirmed that the test results were within the acceptance criteria. Also, during the audit and review, the staff confirmed that based on a review of the plant operating experience, there were no component failures related to the quality of the diesel fuel which led to 3-71the loss of intended function of any component. Finally, the staff reviewed VYNPS work orders.From this review the staff confirmed that a visual inspection was performed in 1996 of the fuel oil tank which revealed no degradation. In addition during this review the staff confirmed that the ultrasonic measurement in 1996 of the tank bottom surface revealed no degradation.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.9, the applicant provided the UFSAR supplement forthe Diesel Fuel Monitoring Program.The applicant committed (Commitment #3) to implement the enhancement to the Diesel FuelMonitoring Program to ensure ultrasonic thickness measurement of the tank bottom surface will be performed every 10 years during tank cleaning and inspection by March 21, 2012.
The applicant committed (Commitment #4) to implement the enhancement to the Diesel Fuel Monitoring Program to specify UT measurements of TK-40-1A bottom surface will have acceptance criterion greater or equal to 60 percent Tnom by March 21, 2012. The applicant committed  (Commitment #46) to implement the enhancement to the Diesel Fuel Monitoring Program to specify that fuel oil in the fire pump diesel storage (day) tank will be analyzed in accordance with ASTM D975-02 and for particulates per ASTM D2276, and fuel oil in the John Deere diesel storage tank will be analyzed for particulates per ASTM D2276 by March 21, 2012.
The applicant committed (Commitment #47) to implement the enhancement to the Diesel Fuel Monitoring Program to specify fuel oil in the common portable fuel oil storage tank will be analyzed in accordance with ASTM D975-02, per ASTM D2276 for particulates, and ASTM D1796 for water and sediment by March 21, 2012.The staff reviewed LRA Section A.2.1.9 and determined that, upon the implementation ofCommitments #3, #4, #46, and #47, the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Diesel Fuel MonitoringProgram, the staff determines that the AMP, with the exceptions and their justifications, is adequate to manage the aging effects for which it is credited. Also, the staff reviewed the enhancements (Commitments #3, #4, #46, and #47) and confirmed that their implementation, prior to the period of extended operation would make the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-723.0.3.2.10  Fatigue Monitoring ProgramSummary of Technical Information in the Application. LRA Section B.1.11 describes the existingFatigue Monitoring Program as consistent, with exceptions and enhancements, with GALL AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary." The Fatigue Monitoring Program tracks the number of critical thermal and pressure transients forselected reactor coolant system components so they do not exceed design limit on fatigue usage. The program validates analyses that explicitly assume a specified number of thermal and pressure fatigue transients by assuring that the actual effective number of transients is not exceeded.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exceptions and enhancements to determine whether the AMP, with the exceptions and enhancements, remained adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the Fatigue Monitoring Program for which the applicantclaimed consistency with GALL AMP X.M1 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's Fatigue Monitoring Program provided assurance that fatigue damage will be adequately managed. The staff finds the applicant's Fatigue Monitoring Program acceptable because it conformed to the recommended GALL AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary," with exceptions and enhancements.Exception 1. In LRA Section B.1.11, the applicant stated an exception to the GALL Reportprogram element "preventive actions." Specifically, the exception states that: The Fatigue Monitoring Program only involves tracking the number of transientcycles and does not include assessment of the impact of reactor water environment on critical components.In the LRA, the applicant stated that the effect of the reactor water environment on fatigue[damage] is addressed as a TLAA (as described in Section 4.3.3) as opposed to being implemented within the Fatigue Monitoring Program.In its letter dated September 17, 2007, the applicant stated that the program will includeassessment of the impact of reactor water environment on critical components and removed this exception from the LRA. The staff finds the removal of this exception acceptable.Exception 2. In LRA Section B.1.11, the applicant stated an exception to the GALL Reportprogram element "detection of aging effects." Specifically, the exception states that: The VYNPS program does not provide for periodic update of the fatigue usagecalculations.
3-73The applicant further stated that the VYNPS program provides for periodic assessment of thenumber of accumulated cycles, and that if a design cycle assumption is approached, corrective action is taken.In its letter dated September 17, 2007, the applicant stated that the program will include periodicreview of accumulated transient cycles and associated updates of fatigue usage calculation, if necessary, and removed this exception from the LRA. The staff finds the removal of this exception acceptable.Enhancement 1. In LRA Section B.1.11, the applicant stated the following enhancement inmeeting the program element "detection of aging effects." Specifically, the enhancement stated:The VYNPS program will be modified to either require periodic update ofcumulative fatigue usage factors (CUFs), or to require update of CUFs if the number of accumulated cycles approaches the number assumed in the design calculation. The staff finds this enhancement acceptable. If the first alternative is adopted, "FatigueMonitoring Program," will be consistent with GALL AMP X.M1. If the second alternative is adopted, together with the commitment to implement the use of a computerized monitoring program (which entails the establishment of a new baseline and then determines CUFs directly),
an acceptable method to ensure that the effects of aging will be adequately managed is provided.Enhancement 2. In LRA Section B.1.11, the applicant stated the following enhancement inmeeting the program element "monitoring and trending." Specifically, the enhancement states:A computerized monitoring program (e.g., FatiguePro) will be used to directlydetermine CUFs for locations of interest. The staff reviewed a sample of CUF calculations and associated reports and VYNPS technicalpersonnel confirmed that the NUREG/CR-6260 locations were among the locations of interest to be monitored.On the basis that CUFs will be determined directly on an ongoing basis, the staff finds that thisenhancement will provide an acceptable method for monitoring and trending fatigue damage.
The staff finds that when the enhancement is implemented, the applicant's Fatigue Monitoring Program will be consistent with GALL AMP X.M1 and will provide additional assurance that the effects of aging will be adequately managed.Enhancement 3. In LRA Section B.1.11, the applicant stated the following enhancement inmeeting the program element "acceptance criteria." Specifically, the enhancement stated:The allowable number of effective transients will be established for monitoredtransients. This will allow quantitative projection of future margin.
3-74The staff finds this enhancement acceptable since when the enhancement is implemented, theapplicant's Fatigue Monitoring Program will be consistent with GALL AMP X.M1 and will provide additional assurance that the effects of aging will be adequately managed.Operating Experience. In LRA Section B.1.11, the applicant stated that the condition reportingprocess documented the discovery of a previously unrecognized fatigue cycle applicable to reactor vessel FW nozzles. Corrective actions included revision of the cycle tracking procedure and of FW nozzle fatigue analysis calculations. This operating experience demonstrates that the corrective action process documents program deficiencies and tracks corrective actions when necessary. For recent reactor shutdowns and startups, cycle limitations did not trend toward exceeding the allowable number of cycles. This operating experience demonstrates that the program continues to monitor plant transients and to track the accumulation of these transients.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience revealed no degradation beyond industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.UFSAR Supplement. In LRA Section A.2.1.11, the applicant provided the UFSAR supplement forthe Fatigue Monitoring Program.The applicant committed (Commitment #5) to modified the Fatigue Monitoring Program torequire periodic update of cumulative fatigue usage factors (CUFs), or to require update of CUFs if the number of accumulated cycles approaches the number assumed in the design calculation by March 21, 2012.The applicant committed (Commitment #6) to use a computerized monitoring program (e.g.,FatiguePro) will be used to directly determine CUFs for locations of interest for the Fatigue Monitoring Program by March 21, 2012.The applicant committed (Commitment #7) to established the allowable number of effectivetransients for monitored transients. This will allow quantitative projection of future margin for the Fatigue Monitoring Program, by March 21, 2012.The staff reviewed LRA Section A.2.1.11 and determines that, upon implementation ofCommitments #5, #6, and #7, the information in the UFSAR supplement provided an adequate summary description of the program, as required by 10 CFR 54.21(d).The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.
Conclusion. On the basis of its audit and review of the applicant's Fatigue Monitoring Program,the staff determines that the AMP, with the exceptions and the associated justifications, is adequate to manage the aging effects for which it is credited. Also, the staff reviewed the enhancements and confirmed that the implementation of the enhancements (Commitments #5, 3-75#6, and #7) prior to the period of extended operation would result in the existing AMP beingconsistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.11  Fire Protection Program Summary of Technical Information in the Application. In LRA Section B.1.12.1, the applicantstated that "Fire Protection Program," is an existing plant program that is consistent with GALL AMP XI.M26, "Fire Protection," with exceptions and enhancements.The Fire Protection Program includes a fire barrier inspection and a diesel-driven fire pumpinspection. The fire barrier inspection requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire-rated doors to ensure that their operability is maintained. The diesel-driven fire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. Corrective actions, confirmation process, and administrative controls in accordance with the requirements of 10 CFR 50 Appendix B are applied to the Fire Protection Program.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The Audit and Review Report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and enhancements and the associated justifications to determine whether the AMP, with the exceptions and enhancements, remains adequate to manage the aging effects for which it is credited.The GALL Report recommends that inspection results are acceptable if there are no visualindications (outside those allowed by approved penetration seal configuration) of cracking, separation of seals from walls and components, separation of layers of material, or ruptures or punctures of seals; no visual indications of concrete cracking, spalling and loss of material of fire barrier walls, ceilings and floors; no visual indications of missing parts, holes, and wear; and no deficiencies in the functional tests of fire doors.The staff reviewed the applicant's procedure acceptance criteria and noted that they allowcracks in poured concrete barriers, fire barriers, concrete block walls, drywall, plaster, silicone foam, pyrocrete, and smoke/gas seals. The staff asked the applicant to justify the plant-specific acceptance criteria's variance from that recommended by the GALL Report. The applicant responded that this acceptance criteria procedure would be revised to require that any recordable indication be identified and entered into the CAP for evaluation and subsequent action, as described below in the discussion of Enhancement 1.The GALL Report recommends that visual inspection by fire protection qualified inspectors ofpenetration seals in walkdowns be performed at least once every refueling cycle. The staff reviewed VYNPS procedure, examination requirements and noted that it did not address inspector qualifications. The staff asked the applicant to explain the inspector qualifications. The 3-76applicant responded that its qualification program was being developed and will includeacceptance criteria, personnel training, and qualification as a "fire protection qualified individual" in accordance with the standards of ANSI 45.2.6.The staff reviewed those portions of the Fire Protection Program for which the applicant claimedconsistency with GALL AMP XI.M26 and found that they are consistent with the GALL AMP.
Furthermore, the staff concludes that the applicant's Fire Protection Program provides assurance that the aging of fire protection components through detailed fire barrier examinations of fire barrier penetration seals, fire barrier walls, ceilings and walls, and through periodic examinations and functional tests of fire-rated doors, will be adequately managed. The Fire Protection Program also manages the aging of the diesel-driven fire pump through periodic testing, and the carbon dioxide fire suppression system through periodic examinations andtesting. The staff finds the applicant's Fire Protection Program acceptable because it conformes to the recommended GALL AMP XI.M26, "Fire Protection," with exceptions and enhancements.Exception 1. In LRA Section B.1.12.1, the applicant stated an exception to the GALL Reportprogram element "scope of program." Specifically, the exception states that: This program is not necessary to manage aging effects for halon fire protectionsystem components. The applicant also noted that the Halon 1301 suppression system is not subject to an AMR.Aging effects for components in the CO 2 system are managed by the System WalkdownProgram.The staff asked the applicant to explain statement regarding the halon fire suppression system.The applicant responded that there was no halon fire suppression system within the scope of license renewal, or that was brought in-scope resulting from requirements of 10 CFR 54.4(a)(2).
The applicant explained that there is a halon fire suppression system for the computer room only, but that there are no UFSAR, TS, or 10 CFR 50, Appendix R, requirements associated with that system. The applicant further explained that VYNPS uses water spray to protect most areas that are typically protected with halon or CO 2 at other nuclear power plants, except that VYNPSwill limit water in areas where there is potential for water to spread radioactive contamination. In those areas, the applicant stated that fires would be fought primarily with portable dry chemical or CO 2 fire extinguishers. Since there is no halon fire suppression system within the scope oflicense renewal, the Fire Protection Program does not discuss aging management of a halon fire suppression system.The staff asked the applicant to explain the statement regarding the CO 2 fire suppressionsystem. The applicant responded that the CO 2 fire suppression system had historically beenplaced in the System Walkdown Program vice the Fire Protection Program. As with the halon fire suppression system, the applicant stated that there were no UFSAR TS or 10 CFR 50, Appendix R, requirements associated with the CO 2 fire suppression system. The staff reviewedthe applicant's procedure and determines that it adequately addressed AERM as identified in the GALL Report. According to this procedure, VYNPS performs visual examinations during periodicformal walkdowns on either monthly or a six-month frequency, depending on the system; and informal walkdown results can be recorded and evaluated at any time. VYNPS has committed (Commitment #30) to revise the System Walkdown Program to specify CO 2 system inspections 3-77every six months. In its letter, dated March 23, 2007, the applicant revised its LRA to includefunctional testing of the CO 2 system in accordance with Technical Requirements Manual (TRM)4.13.D surveillance requirements.The staff reviewed the applicant's response and concludes that there is no halon firesuppression system within the scope of license renewal and that the applicant adequately addresses the aging management of the CO 2 fire suppression system with the SystemWalkdown Program and functional testing in accordance with their TRM 4.13.D surveillance requirements. On this basis, the staff finds this exception to be acceptable.Exception 2. In LRA Section B.1.12.1, the applicant stated an exception to the GALL Reportprogram element "detection of aging." Specifically, the exception states that: The GALL Report program stated that 10 percent of each type of penetration sealshould be visually inspected at least once every refueling outage. The VYNPS program specifies inspection of approximately 25 percent of the seals (regardless of seal type) each operating cycle, with all accessible fire barrier penetration seals being inspected at least once every four operating cycles.The applicant also stated that since aging effects are typically manifested over several years,this variation in inspection frequency is insignificant.The staff asked the applicant to explain the rationale for the inspection frequency of thepenetration seals. The applicant responded that the examination frequency is conservative. The staff asked the applicant to explain how it addressed inaccessible penetration seals. The applicant responded that the environment to which the inaccessible penetrations seals are exposed is similar, if not identical, to that of the accessible penetrations seals, and that it considered the condition of accessible penetration seals to be representative of the inaccessiblepenetration seals. Thus, inaccessible seals would not necessarily be included in any inspectionexpansion, when recordable indications are detected during the performance of an inspection, but would be included in replacement of accessible penetration seals, as determined by engineering evaluation.The staff evaluated the applicant's response and determined that it was unacceptable toconsider the inspection of accessible seals representative of inaccessible seals. In its letter,dated March 13, 2007, the applicant revised the VYNPS fire barrier penetration seal inspection program to remove the word "accessible" from the exception. Both GALL AMP XI.M26 and the applicant's proposed program inspect a sample of each type of seal every refueling outage. By inspecting approximately 25 percent of the seals each refueling outage, the VYNPS fire barrier seal inspection program will accomplish inspection of 100 percent of the penetration seals in 6 years or four refueling outage (VYNPS refueling outage is every 18-month). GALL AMP XI.M26 recommends inspection of 100 percent of the penetration seals over 20 years. The staff evaluated the applicant's program and determined that overall it meets or exceeds thepenetration seal inspection frequency recommended in the GALL Report and it adequately addresses the aging mechanism requiring management of fire barrier penetration seals. On the basis of its review, the staff concludes that the VYNPS fire barrier penetration seal inspection program is effective in finding signs of penetration seal degradation during the period of 3-78extended operation. The staff is adequately assured that the fire barrier penetration seals will beconsidered appropriately during plant aging management activities and will continue to perform applicable intended functions consistent with the CLB for the period of extended operation.Enhancement 1. In LRA Section B.1.12.1, the applicant stated the following enhancement inmeeting the program elements "parameters monitored/inspected" and "acceptance criteria."
Specifically, the enhancement states:Procedures will be enhanced to specify that fire damper frames in fire barriersshall be inspected for corrosion. Acceptance criteria will be enhanced to verify no significant corrosion.The staff asked the applicant to explain this enhancement (Commitment #8). The applicantresponded that, in the course of an evaluation conducted in preparation for license renewal, this procedure had been determined not to adequately address the concerns associated with all the AERMs, as recommended in the GALL Report. The staff reviewed the pertinent procedure and agrees that the procedure instructions and acceptance criteria did not adequately address the aging effect of corrosion. The fire dampers are in the ventilation ducts and are considered to be susceptible to corrosion. The staff also asked the applicant to clarify the stated objective of no "significant" corrosion. The applicant responded that any recordable indication would be forwarded to the CAP for evaluation and subsequent action. The staff reviewed the applicant's response and determines that it adequately addresses theissue of corrosion of the dampers. The staff determines that the applicant's response is appropriate. The staff finds this enhancement acceptable because, when the enhancement is implemented, the Fire Protection Program, will be consistent with GALL AMP XI.M26 in that it will address all AERMs, and will provide additional assurance that the effects of aging will be adequately managed.Enhancement 2. In LRA Section B.1.12.1, the applicant stated the following enhancement inmeeting the program elements "parameters monitored/inspected" and "acceptance criteria."
Specifically, the enhancement stated:Procedures will be enhanced to state that the diesel engine subsystems(including the fuel supply line) shall be observed while the pump is running.
Acceptance criteria will be enhanced to verify that the diesel engine did not exhibit signs of degradation while it was running; such as fuel oil, lube oil, coolant, or exhaust gas leakage.The staff asked the applicant to explain this enhancement. The applicant responded that, in thecourse of an evaluation conducted in preparation for license renewal, this procedure had been determined not to adequately address the concerns associated with all the AERMs, as recommended in the GALL Report. The staff reviewed the pertinent procedure and determined that the procedure instructions and acceptance criteria did not adequately address all the AERMs, as recommended in the GALL Report, and noted that the fuel supply line was not mentioned. When the staff asked the applicant about the absence of the fuel supply line, the applicant stated that evidence of corrosion inside the fuel supply line would appear as corrosion products in the fuel filter, which would result in a condition report and an evaluation. The 3-79applicant added that the fuel condition is monitored by the Diesel Fuel Oil Monitoring Program.The applicant agreed that the procedure enhancement would be expanded to include detection of degradation of the fuel supply line (Commitment #9). The staff reviewed the applicant's response and finds this enhancement acceptable. When theenhancement is implemented the "Fire Protection Program," will be consistent with GALL AMP XI.M26 and will provide additional assurance that the effects of aging will be adequately managed.Operating Experience. In LRA Section B.1.12.1, the applicant stated that numerous conditionreports of minor degradation of penetration seals and fire barriers show that periodic inspections effectively monitor for AERM, identify aging effects, and appropriately resolve them. QA surveillances, QA audits, and staff integrated and triennial inspections since 1999 revealed no issues or findings with impact on program effectiveness.The applicant stated that VYNPS has a comprehensive operating experience program thatmonitors industry events and issues, and assesses them for applicability to its own operations. In addition, VYNPS has a CAP that is used to track, trend, and evaluate significant plant issues and events. Those issues and events, whether industry or plant-specific, that are potentially significant to the Fire Protection Program are evaluated. The Fire Protection Program is augmented, as appropriate, when these evaluations show that changes to this program will enhance its effectiveness.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.12, the applicant provided the UFSAR supplement forthe Fire Protection Program.The applicant committed (Commitment #8) to enhance the procedures for the Fire ProtectionProgram to specify that fire damper frames in fire barriers shall be inspected for corrosion and to enhance the acceptance criteria to verify no significant corrosion by March 21, 2012.The applicant committed (Commitment #9) to enhance the procedures for the Fire ProtectionProgram to state that the diesel engine subsystems (including the fuel supply line) shall beobserved while the pump is running and to enhance the acceptance criteria to verify that the diesel engine did not exhibit signs of degradation while it was running; such as fuel oil, lube oil,coolant, or exhaust gas leakage, documented as Commitment #9, as described in VYNPS AMP B.1.12.1 by March 21, 2012.
3-80The applicant committed (Commitment #30) to revise the System Walkdown Program to specify CO 2 system inspections every six months by March 21, 2012.The staff reviewed LRA Section A.2.1.12 and determined that, upon implementation ofCommitments #8, #9, and #30, the information in the UFSAR supplement provided an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Fire Protection Program, thestaff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent with the addition of Commitments #8, #9, and #30. In addition, the staff reviewed the exceptions and their justifications and determines that the AMP, with the exceptions, is adequate to manage the aging effects for which it is credited. Also, the staff reviewed the enhancements and confirmed that their implementation prior to the period of extended operation would make the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.12  Fire Water System Program Summary of Technical Information in the Application. LRA Section B.1.12.2 describes theexisting Fire Water System Program as consistent, with exception and enhancements, with GALL AMP XI.M27, "Fire Water System." This program applies to water-based fire protection systems consisting of sprinklers, nozzles,fittings, valves, hydrants, hose stations, standpipes, and above-ground and underground piping and components tested in accordance with applicable National Fire Protection Association (NFPA) codes and standards. Such testing assures system functionality. Many of these systems normally are maintained at required operating pressure and monitored to immediately detect leakage causing loss of system pressure and to initiate corrective actions. In addition, a sample of sprinkler heads will be inspected in accordance with the guidance of NFPA 25 (2002 Edition)
Section 5.3.1.1.1, which states that, "where sprinklers have been in place for 50 years, they shall be replaced or representative samples from one or more sample areas shall be submitted to a recognized testing laboratory for field service testing." NFPA 25 also provides guidance for this sampling every 10 years after initial field service testing.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exception and enhancements to determine whether the AMP, with the exception and enhancements, remained adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the Fire Water System Program for which the applicantclaims consistency with GALL AMP XI.M27 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's Fire Water System Program provided assurance that the aging effects for the components in the scope of its Fire Water System Program are adequately managed. The staff finds the applicant's Fire Water System Program 3-81acceptable because it conforms to the recommended GALL AMP XI.M27, "Fire Water System,"with exceptions and enhancements.Exception 1. In LRA Section B.1.12.2, the applicant stated an exception to the GALL Reportprogram element "detection of aging effects." Specifically, the exception states that: NUREG-1801 specifies annual fire hydrant hose hydrostatic tests. In accordancewith the VYNPS program, hydrostatic test of outside hoses occurs once per 24 months; and hydrostatic test of inside hoses occurs once per three years.The staff asked the applicant to provide justification for the exception. The applicant was askedwhether the 24 or 36 months is part of their CLB. In response, the applicant provided its TRM of the current licensing requirements. The staff determined that the exception was inconsistent with the TRM. In its letter, dated March 12, 2007, the applicant revised the exception to specify that fire hydrant hoses will be tested, inspected, and replaced, if necessary, in accordance with NFPA standards (Commitment #49).On the basis that this exception is revised and the applicant will perform the fire hydrant hosetest, inspections, and replacement, consistent with its TRM, the staff finds this acceptable.Exception 2. In LRA Section B.1.12.2, the applicant stated an exception to the GALL Reportprogram element "detection of aging effects." Specifically, the exception states that: NUREG-1801 specifies annual gasket inspections. In accordance with theVYNPS program, visual inspection, re-racking and replacement of gaskets in couplings occurs at least once per 18 months.The staff asked the applicant to explain this exception. The applicant responded that the agingeffects of gaskets are manifest over the period of several years, and that minor differences in inspection and testing frequencies are insignificant. In addition, the applicant stated that a review of the operating experience did not reveal age-related failures of the fire water system components that led to loss of intended function. However, in a letter dated January 4, 2007, the applicant provided a revision to its LRA to delete this exception and to specify that inspections of the fire hydrant gasket will be performed annually (Commitment #31).On the basis that this exception is deleted and the applicant will perform the fire hydrant gasketinspection annually, consistent with the GALL Report recommendation, the staff finds this acceptable.Exception 3. In LRA Section B.1.12.2, the applicant stated an exception to the GALL Reportprogram element "detection of aging effects." Specifically, the exception states that: NUREG-1801specifies annual fire hydrant flow tests. In accordance with theVYNPS program, verification of operability and of no flow blockage occurs at least once every three years.
3-82The staff asked the applicant to justify the extension of the fire hydrant flow test from one year,as recommended by the GALL Report, to three years. The applicant responded that it had always performed the fire hydrant flow test on a three -year frequency, which was supported by VYNPS operational experience, that is, there was no justification for the extension. However, in a letter dated January 4, 2007, the applicant provided a revision to its LRA to delete this exception and specify that the fire hydrant flow tests will be performed annually (Commitment
#31).On the basis that this exception is deleted and the applicant will perform the fire hydrant flowtests annually, consistent with the GALL Report recommendation, the staff finds this acceptable.Exception 4
. In LRA Section B.1.12.2, the applicant stated an exception to the GALL Reportprogram element "detection of aging effects." Specifically, the exception states that: NUREG-1801specifies sprinkler systems inspections once every refueling outage.In accordance with the VYNPS program, visual inspection of deluge and pre-action system piping to verify their integrity occurs at least once per 24 months. Since aging effects are typically manifested over several years, differences in inspection and testing frequencies are insignificant.The staff asked the applicant to justify the extension of the visual inspection frequency fromonce every refueling outage (20 months), in accordance with the recommendation of the GALL Report, to 24 months. The applicant responded that the aging effects of sprinkler heads are manifest over the period of several years, and that minor differences in inspection and testing frequencies (four months) are insignificant. The staff reviewed the applicant's response and operating experience. The staff finds that a loss of intended function of the sprinkler heads due to age-related failures is not likely to occur over the four additional months. On this basis, the staff finds this exception acceptable.Enhancement 1. In LRA Section B.1.12.2, the applicant stated the following enhancement inmeeting the program element "detection of aging effects." Specifically, the enhancement stated:A sample of sprinkler heads will be inspected using guidance of NFPA 25 (2002Edition) Section 5.3.1.1.1. NFPA 25 also contains guidance to repeat this sampling every 10 years after initial field service testing.The staff asked the applicant to provide an explanation as to why this enhancement will provideadditional assurance that the effects of aging will be adequately managed. The applicant responded that this enhancement to the LRA is written in accordance with the NFPA guidance, rather than the GALL Report recommendation; however, the applicant added that the NFPA guidance for this enhancement is essentially identical to the GALL Report recommendation. The staff reviewed the fire water system procedures and noted that VYNPS followed NFPA guidance in all aspects of sprinkler head examination. The staff finds this enhancement acceptable since when the enhancement is implemented the Fire Water System Program, will be consistent with GALL AMP XI.M27 and will provide additional assurance that the effects of aging will be adequately managed.
3-83Enhancement 2. In LRA Section B.1.12.2, the applicant stated the following enhancement inmeeting the program element "detection of aging effects." Specifically, the enhancement states:Wall thickness evaluations of fire protection piping will be performed on systemcomponents using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. These inspections will be performed before the end of the current operating term and at intervals thereafter during the period of extended operation. Results of the initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function.The staff asked the applicant to provide an explanation as to why this enhancement wouldprovide additional assurance that the effects of aging on fire water system piping would be adequately managed. The applicant responded that fire water system piping is flow tested in accordance with NFPA guidelines every three years. The applicant further responded that the recommendation to monitor wall thinning was a recommendation of the GALL Report, and that VYNPS included this enhancement to this attribute to perform wall thickness examinations of fire water system piping using volumetric examinations to identify the loss of material due to corrosion. The applicant stated that these examinations would be performed before the end of the current operating term and at intervals during the period of extended operation on an appropriate frequency that would be determined based on the initial examination results.The staff reviewed the applicant's response and agrees that it adequately addresses therecommendations of the GALL Report. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented, "Fire Water System Program," will be consistent with GALL AMP XI.M27 and will provide additional assurance that the effects of aging will be adequately managed.Operating Experience. LRA Section B.1.12.2 states that in 2003 open-head deluge nozzles wereverified to be free of damage and free of obstructions that could inhibit the spray pattern.
Absence of loss of material from the deluge nozzles proves that the program is effective for managing loss of material for water suppression fire protection system components. QA audits and staff integrated and triennial inspections from 2001 to 2004 revealed no issues or findings that could impact program effectiveness.The applicant stated, during the audit and review, that VYNPS has a comprehensive operatingexperience program that monitors industry events and issues, and assesses them for applicability to its own operations. In addition, VYNPS has a CAP that is used to track, trend, and evaluate significant plant issues and events. Those issues and events, whether industry or plant-specific, that are potentially significant to the Fire Water System Program are evaluated.
The Fire Water System Program is augmented, as appropriate, when these evaluations show that changes to this program will enhance its effectiveness.
1NFPA 25 requires that sprinkler heads be replaced or representative samples from one or more sampleareas be submitted to a recognized testing laboratory for field services testing. In the VYNPS program arepresentative sample of sprinkler heads will be submitted to a recognized testing laboratory for services testing. TheStaff notes that the VYNPS sprinkle r heads inspection program appears to elim inate the option to just replace asprinkler head after 50 years service unless it first undergoes laboratory testing. This implies that, if a sprinkler headis obviously corroded and requires replacement, the VYNPS may first have to send that sprinkler head to a testinglaboratory before replacing it, a seemingly unnecessary burden.3-84The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.13, the applicant provided the UFSAR supplement forthe Fire Water System Program.The applicant committed (Commitment #10) to implement the enhancement to the Fire WaterSystem Program to inspect a sample of sprinkler heads using guidance of NFPA 25 (2002 Edition) Section 5.3.1.1.1 by March 21, 2012. When sprinklers have been in place for 50 years a representative sample of sprinkler heads will be submitted to a recognized testing laboratory for field service testing
: 1. This sample will be repeated every 10 years, by March 21, 2012.The applicant committed in (Commitment #11) to implement the enhancement to the Fire WaterSystem Program to specify that wall thickness evaluations of fire protection piping will be performed on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion by March 21, 2012. These inspections will be performed before the end of the current operating term and at intervals thereafter during the period of extended operation. Results of the initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function, by March 21, 2012.The applicant committed (Commitment #31) to revise the Fire Water System Program to specifyannual fire hydrant gasket inspections and flow tests by March 21, 2012.The applicant committed (Commitment #49) to revise the Fire Water System Program to specifythat fire hydrant hoses will be tested, inspected, and replaced, if necessary, in accordance with NFPA standards by March 21, 2012.The staff reviewed this section and determined that, upon implementation of Commitments #10,#11, #31, and #49, the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-85 Conclusion. On the basis of its audit and review of the applicant's Fire Water System Program,the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent with the addition of Commitments #10, #11, #31, and #49.
In addition, the staff reviewed the exception and their justifications and determines that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. Also, the staff reviewed the enhancements and confirmed that their implementation prior to the period of extended operation would make the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.13  Oil Analysis Program Summary of Technical Information in the Application. LRA Section B.1.20 describes the existingOil Analysis Program as consistent, with exception, with GALL AMP XI.M39, "Lubricating Oil Analysis." The Oil Analysis Program maintains oil systems free of contaminants (primarily water andparticulates), preserving an environment not conducive to loss of material, cracking, or fouling.
Sampling frequencies are based on vendor recommendations, accessibility during plant operation, equipment importance to plant operation, and previous test results.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the Oil Analysis Program for which the applicant claimedconsistency with GALL AMP XI.M39 and finds that they are consistent with the GALL AMP.
Furthermore, the staff concludes that the applicant's Oil Analysis Program provided assurance that oil systems are free of contaminants which preserves an environment that is not conducive to loss of material, cracking or fouling. The staff finds the applicant's Oil Analysis Program acceptable because it conformed to the recommended GALL AMP XI.M39, "Lubricating Oil Analysis," with an exception.Exception. In LRA Section B.1.20, the applicant stated an exception to the GALL Reportprogram element "parameters monitored/inspected." Specifically, the exception states that: Flash point is not determined for sampled oil.The applicant also stated, that analyses of filter residue or particle count, viscosity, totalacid/base (neutralization number), water content, and metals content are performed on the sampled oil, but the flash point of the oil is not determined.
3-86The applicant indicated that extensive testing and analyses is performed on all of the sampled oilto verify that the oil is suitable for continued use. However, determination of the oil flash point is not performed as part of the program. The applicant also stated that it performs a fuel dilution test in lieu of performing flash point testing on the emergency diesel generators (EDGs), diesel driven fire pump, and the John Deere Diesel generator. This test accomplishes the same goal as the flash point test but is more prescriptive. The fuel dilution test determines the percent by volume of both fuel and water, the analysis can determine the cause of the change in flash point without having to conduct additional tests and corrective actions, and if required, could be implemented on a timelier basis. On the basis that the fuel dilution test is more prescriptive and timely, the staff finds this exception acceptable.Operating Experience. LRA Section B.1.20 states that a negative trend was noted in the lube oilanalysis report for the P-40-1A diesel fire pump. Oil was drained, flushed, and refilled. A lube oil sample taken on the "B" EDG indicated a temporary abnormally high non-abrasive silicon level caused by gasket sealant materials used during the last EDG overhaul. Although acceptance criteria do not include an upper threshold for silicon, re-sampling confirmed that the silicon level had gone down. Corrective action following negative trends and abnormal samples proves that the program is effective at preserving an environment not conducive to loss of material, cracking, or fouling. Recent QA surveillance and self-assessment revealed no issues or findings that could impact program effectiveness.The staff reviewed an assessment of the maintenance programs which was performed by theQuality Assurance Group and the Component Engineering assessment of the Predictive Maintenance Programs. This review confirmed that the lube Oil Analysis Program effectively had implemented the programmatic and regulatory requirements at that point in time. The review of these reports confirmed that the Oil Analysis Program was effectively monitoring the lube oil and was trending the data to allow the appropriate actions to be taken. In addition, the staff confirmed that there have been no component failures to date at VYNPS related to lube oil contamination.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.22, the applicant provided the UFSAR supplement forthe Oil Analysis Program. The staff reviewed this section and determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-87 Conclusion. On the basis of its audit and review of the applicant's Oil Analysis Program, the staffdetermines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justifications and determines that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.14  Reactor Head Closure Studs Program Summary of Technical Information in the Application. LRA Section B.1.23 describes the existingReactor Head Closure Studs Program as consistent, with exception, with GALL AMP XI.M3, "Reactor Head Closure Studs." This program includes ISI in conformance with the requirements of ASME Code, Section XI,Subsection IWB, and preventive measures (e.g., rust inhibitors, stable lubricants, appropriate materials) to mitigate cracking and loss of material of reactor head closure studs, nuts, washers, and bushings.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the Reactor Head Closure Studs Program for which theapplicant claimed consistency with GALL AMP XI.M3 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's Reactor Head Closure Studs Program provided assurance that the effects of cracking due to SCC/IGSCC and loss of materialdue to wear will be adequately managed so that the intended functions of components within the scope of license renewal will be maintained during the period of extended operation. The staff finds the applicant's Reactor Head Closure Studs Program acceptable because it conformed tothe recommended GALL AMP XI.M3, "Reactor Head Closure Studs," with an exception.Exception. In LRA Section B.1.23, the applicant stated an exception to the GALL Reportprogram element "detection of aging effects." Specifically, the exception states that: When reactor head closure studs are removed for examination, either a surfaceor volumetric examination is allowed. The applicant noted that cracking initiates on the outside surfaces of bolts and studs. Therefore,a qualified surface examination meeting the acceptance standards of IWB-3515 provides at least the sensitivity for flaw detection that an end shot ultrasonic examination provides on bolts or studs. Thus, when reactor head closure studs are removed for examination, either a surface or volumetric examination is allowed.The applicant stated that its detection of aging effects is consistent with ASME Section XICode Case N-652 which allows surface examination to be substituted for volumetric examination 3-88when bolting is removed for examination. Code Case N-652 has been endorsed by the NRC perTable 1 in RG 1.147, Revision 14. In accordance with Code Case N-652, future examinations will be visual only. The staff determines that either a surface or volumetric examination can reliably reveal cracking and loss of material due to corrosion or wear. On this basis, the staff finds that this is not an exception to the GALL Report. In its letter dated July 14, 2006, the applicant deleted this exception from the LRA.Operating Experience. LRA Section B.1.23 states that recent (2002 and 2004) visual andultrasonic inspections of reactor vessel studs, nuts, bushings, and washers revealed no recordable indications. Absence of recordable indications proves that the program is effective for managing loss of material and cracking for applicable components.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.25, the applicant provided the UFSAR supplement forthe Reactor Head Closure Studs Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Reactor Head Closure StudsProgram, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justifications and determines that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-893.0.3.2.15  Reactor Vessel Surveillance ProgramSummary of Technical Information in the Application. LRA Section B.1.24 describes the existingReactor Vessel Surveillance Program as consistent, with enhancement, with GALL AMP XI.M31, "Reactor Vessel Surveillance." This program manages reduction in fracture toughness of reactor vessel beltline materials tomaintain the pressure boundary function of the reactor pressure vessel (RPV) for the period of extended operation. The applicant participates in the BWRVIP Integrated Surveillance Program (ISP) as approved by License Amendment 218. This program monitors changes in the fracture toughness properties of ferritic materials in the RPV beltline region. As BWRVIP-ISP capsule test reports for representative RPV materials become available the actual shift in the reference temperature for nil-ductility transition of the vessel material may be updated. In accordance with 10 CFR Part 50, Appendix H, the applicant reviews relevant test reports for compliance with fracture toughness requirements and pressure-temperature limits. BWRVIP-116, "BWR Vessel and Internals Project Integrated Surveillance Program (ISP) Implementation for License Renewal," describes the design and implementation of the ISP during the period of extended operation. BWRVIP-116 identifies additional capsules, their withdrawal schedule, andcontingencies to ensure that the requirements of 10 CFR Part 50 Appendix H are met for the period of extended operation.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the enhancement, remained adequate to manage the aging effects for which it is credited.In LRA Appendix B, Reactor Vessel Surveillance Program, the applicant described its AMP tomanage irradiation embrittlement of the RPV through testing that monitors RPV beltline materials. The LRA stated that the RPV surveillance program will be enhanced by making it consistent with the BWRVIP ISP for the period of extended operation prior to the VYNPS entering its period of extended operation. The applicant has implemented the BWRVIP ISP which is based on the BWRVIP-78 report,"BWR Integrated Surveillance Program Plan," and the BWRVIP-86-A report, "BWR Vessel and Internals Project, BWR Integrated Surveillance Program Implementation." These reports are consistent with the GALL AMP XI.M31, "Reactor Vessel Surveillance," for the period of the current VYNPS license. The staff concludes that the BWRVIP ISP in the BWRVIP-78 and BWRVIP-86-A reports is acceptable for BWR applicant implementation provided that all participating applicants use one or more compatible neutron fluence methodologies acceptable to the staff for determining surveillance capsule and RPV neutron fluences. The staff's acceptance of the BWRVIP ISP for the current term at VYNPS is documented in the staff's SE dated March 29, 2004, which is addressed in VYNPS Amendment 218.
The BWRVIP developed an updated version of the ISP in the BWRVIP-116 report, "BWR Vessel And Internals Project, Integrated Surveillance Program Implementation For License Renewal,"
which provides guidelines for an ISP to monitor neutron irradiation embrittlement of the limiting RPV beltline materials for all U.S. BWR power plants for the period of extended operation. The 3-90applicant stated in the Reactor Vessel Surveillance Program, and in the Updated Final SafetyAnalysis Report (UFSAR) supplement Section A.2.1.26, "Reactor Vessel Surveillance Program,"
that it will implement the ISP specified in the BWRVIP-116 report. The staff reviewed the UFSAR Supplement Section A.2.1.26 to determine whether it provides an adequate description of the program. In RAI B.1.24-1, by letter dated August 16, 2006, the staff requested that the applicant commit tothe following in the Reactor Vessel Surveillance Program and in UFSAR Supplement (LRA Section A.2.1.26):The BWRVIP-116 report which was approved by the staff will be implemented at VYNPSwith the conditions documented in Sections 3 and 4 of the staff's final SE for the BWRVIP-116 report dated March 1, 2006.In response to RAI B.1.24-1, by letter dated September 20, 2006, the applicant stated that itwould update UFSAR Supplement Section A.2.1.26 and the Reactor Vessel Surveillance Program to include the aforementioned commitment (Commitment #38) proposed by the staff.
The staff finds that its concern described in RAI B.1.24-1 is resolved.An ISP used as a basis for a facility's RPV surveillance program must be reviewed and approvedby the staff as required by 10 CFR 50, Appendix H. The ISP to be used by the applicant is a program that was developed by the BWRVIP and the applicant will apply the BWRVIP ISP as the method by which the VYNPS will comply with the requirements of 10 CFR Part 50, Appendix H. The BWRVIP ISP identifies capsules that must be tested to monitor neutron radiation embrittlement for all applicants participating in the ISP and identifies capsules that need not be tested (standby capsules). Table 3-3 of the BWRVIP-116 report indicates that the remaining capsule from VYNPS is not to be tested. This untested capsule was originally part of the applicant's plant-specific surveillance program and has received significant amounts of neutron radiation.In RAI B.1.24-2, by letter dated August 16, 2006, the staff requested that the applicant commit toinclude the following in the UFSAR Supplement (LRA Section A.2.1.26):If the VYNPS standby capsule is removed from the RPV without the intent to test it, thecapsule will be stored in a manner which maintains it in a condition which would permit its future use, including during the period of extended operation, if necessary.In response to RAI B.1.24-2, by letter dated September 20, 2006, the applicant stated that itwould incorporate the staff's aforementioned commitment (Commitment #39) in UFSAR Supplement Section A.2.1.26. The staff finds that the concern described in RAI B.1.24-2 is resolved.On the basis of its review, the staff finds that the applicant has demonstrated that the effects ofaging due to loss of fracture toughness of the RPV beltline region will be adequately managed, so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-91Operating Experience. LRA Section B.1.24 states that the applicant participates in the BWRVIPISP as incorporated into the plant technical specifications by Amendment 218. The fact that it participates in the BWRVIP ISP means future operating experience from all participating BWRs will be factored into this program. The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff concludes that this program element is acceptable.UFSAR Supplement. The applicant described the reactor materials surveillance program as anexisting program in LRA Section A.2.1.26. The program uses periodic testing of metallurgical surveillance samples to monitor the loss of fracture toughness of the RPV beltline region materials consistent with the requirements of 10 CFR Part 50, Appendix H. The applicant further stated that it will implement the staff-approved BWRVIP-116 report for the period of extended operation. The BWRVIP-116 report was approved by the staff and, as described in the staff evaluation section. The applicant made a commitment (Commitment #38) to include the following statement in the UFSAR Supplement (LRA Section A.2.1.26) by March 21, 2012:The BWRVIP-116 report which was approved by the staff will be implemented atVYNPS with the conditions documented in Sections 3 and 4 of the staff's final SE for the BWRVIP-116 report dated March 1, 2006.As to the status of the remaining VYNPS standby capsule, the applicant made a commitment(Commitment #39) to incorporate the following statement in the UFSAR Supplement (LRA Section A.2.1.26) by March 21, 2012:If the VYNPS standby capsule is removed from the RPV without the intent to test it, the capsule will be stored in manner which would permit its future use, if necessary.The staff reviewed the applicant's proposed revision to UFSAR Supplement Section A.2.1.26and determines that by committing to implement the most recent staff-approved version of the BWRVIP-116 report, the applicant demonstrated its compliance with the requirements of 10 CFR Part 50, Appendix H.The staff's review determined that the following license condition will be required to ensure thatchanges in the withdrawal schedule for the capsule that is specified in the BWRVIP-116 report will be submitted for staff review and approval:All capsules placed in storage must be maintained for future insertion. Anychanges to storage requirements must be approved by the NRC, as required by 10 CFR Part 50, Appendix H.
 
The staff concluded that the information provided in the UFSAR Supplement for the aging management of systems and components discussed above is equivalent to the information in NUREG-1801 and therefore provides an adequate summary of program activities (pending incorporation of Commitments #38 and #39) as required by 10 CFR 54.21(d).
3-92 Conclusion. On the basis of its audit and review of the applicant's Reactor Vessel SurveillanceProgram, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent with the addition of Commitments #38 and #39.
Also, the staff reviewed the enhancement and confirmed that their implementation prior to the period of extended operation would make the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.16  Service Water Integrity Program Summary of Technical Information in the Application. LRA Section B.1.26 and LRA supplementdated March 23, 2007, describes the existing Service Water Integrity Program as consistent, with exceptions and an enhancement, with GALL AMP XI.M20, "Open-Cycle Cooling Water System." This program implements the recommendations of GL 89-13 to manage aging effects on theservice water systems (SWS) for the period of extended operation. The SWS include the service water (SW), residual heat removal service water (RHRSW), and alternate cooling systems. The program includes surveillance and control techniques to manage aging effects in the SWS or SCs they serve. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exceptions to determine whether the AMP, with the exceptions, remained adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the Service Water Integrity Program for which the applicantclaimed consistency with GALL AMP XI.M20 and finds that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's Service Water Integrity Program demonstrated that the aging of the SWS will be properly managed for the period of extended operation. However, due to a history of aggressive aging effects, the applicant stated that future proper management of the SWS may include major components replaced with components made of materials less susceptible to aging in raw water. The staff finds the applicant's Service Water Integrity Program acceptable because it conformed to the recommended GALL AMP XI.M20, "Open-Cycle Cooling Water System," with exceptions.Exception 1. In LRA Section B.1.26, the applicant stated an exception to the GALL Reportprogram element "preventive actions." Specifically, the exception states that: The GALL Report stated that system components are lined or coated.Components are lined or coated only where necessary to protect the underlying metal surfaces. The applicant noted that the GALL Report stated that system components are constructed ofappropriate materials and lined or coated to protect the underlying metal surfaces from being 3-93exposed to aggressive cooling water environments. Not all VYNPS system components are linedor coated. Components are lined or coated only where necessary to protect the underlying metal surfaces.The applicant was asked to provide the original (or current if pipe has been replaced) materialand lining specification for the buried piping which is part of the SWS, including the alternate cooling system. The applicant stated that no piping had been replaced and provided the original VYNPS piping specification, which showed the piping for the SW and alternate cooling water systems piping to be carbon steel material and not internally lined or coated. The applicant further stated that the only coated components in the SWS are a few valve body internals and heat exchanger heads that are currently and will continue to be inspected as part of the Service Water Integrity Program. The staff reviewed the SWS piping specifications and determined that the system piping is notinternally lined or coated. VYNPS operating experience demonstrates that the lack of internal linings or coatings has resulted in the system experiencing aggressive aging effects. The applicant stated that to address the aggressive aging effects on the system due to the lack of protective internal linings or coatings, changes have been made at VYNPS in accordance with the Service Water Integrity Program. The applicant stated during the audit and review that changes have been made to the sampling and chemical treatment process. New chemical addition pumps were installed and sampling implemented for SW components during inspections However, VYNPS is limited in accordance with environmental controls to no more than two hours a day of chemical treatment to the SWS. VYNPS has also begun chemical treatment of SW lines not normally inservice. VYNPS also inspects the system every refueling outage. The applicant stated that one method being considered to manage aging is system piping replacement with materials less susceptible to the aging effects of raw water. The staff finds that VYNPS is taking measures with inspections and chemical treatments inaccordance with the Service Water Integrity Program to compensate for the SWS components in general not having internal protective linings or coatings. On this basis, the staff finds this exception acceptable.Exception 2. In LRA Section B.1.26, the applicant stated an exception to the GALL Reportprogram element "monitoring and trending." Specifically, the exception states that: The GALL Report stated that testing and inspections are performed annually andduring refueling outages. The VYNPS program requires tests and inspections each refueling outage. The applicant noted that the GALL Report program entails testing and inspections performedannually and during refueling outages. The VYNPS program requires tests and inspections each refueling outage, but not annually. Since aging effects are typically manifested over several years, the difference in inspection and testing frequency is insignificant.
3-94The applicant stated, in the LRA, that its Service Water Integrity Program requires tests andinspections each refueling outage. The applicant stated in its program basis document that inspection scope, method, and testing frequencies are in accordance with VYNPS commitments in accordance with GL 89-13. Tests and inspections are done during refueling outages and other outages as necessary.The staff finds VYNPS is in compliance with its commitment in accordance with GL 89-13 toinspect and perform testing on the SWS each refueling outage. Outages at VYNPS are generally performed on an eighteen month cycle. The staff also determines that since aging effects typically manifest over several years, the difference in inspection and testing frequency is not significant. On this basis, the staff finds this exception acceptable.Enhancement. In the LRA supplement dated March 23, 2007, the applicant stated the followingenhancement in meeting the GALL Report program element "scope of program." Specifically, the enhancement stated:Enhance the Service Water Integrity Program to require a periodic visualinspection of the RHRSW pump motor cooling coil internal surface for loss of material.The staff reviewed the enhancement and its evaluation is documented in the VYNPS - NRCLicense Renewal Inspection Report 05000271/2007006. The staff determines that performing periodic visual inspection of the RHRSW pump motor cooling coil internal surface is acceptable.
On the basis, the staff finds this enhancement acceptable since when the enhancement is implemented the Service Water Integrity Program will be consistent with GALl AMP XI.M20 and will provide additional assurance that the effects of aging will be adequately managed.Operating Experience. LRA Section B.1.26 states that recent performance test and inspectionresults (2004) prove that the program is effective for managing component aging effects, For example, SW-cooled diesel generator heat exchanger performance testing revealed no significant performance degradation, RHR heat exchanger inspection revealed no loss of material, cracking or fouling, a SW check valve internal visual inspection revealed no loss of material, and internal visual inspection of a SW pipe by fiber optics revealed no loss of material.
Ultrasonic wall thickness measurements taken in October 2003 and January 2004 in the vicinity of known wall-thinning in a SW pipe revealed that the pipe wall thickness had not changed and that the structural integrity of the piping would be maintained until the pipe section could bereplaced in September 2004. Accelerated monitoring in the vicinity of an indication is assurance that the program is effective for managing component loss of material. A staff inspection of the SWS in 2002 determines that mitigation of MIC buildup had not been effective as evidenced by more than 20 SWS leaks. A self-assessment, including independent evaluation by industry experts, was completed on December 20, 2002. Protocols for use of biocides to mitigate MIC were revised and the processes for analysis, trending, and interpretation of results were enhanced. Resolution of this issue is assurance that the program will manage component aging effects.The staff finds the listed operating experience up through 2002 indicates that VYNPS hadperformed inadequately in managing the aging effects of raw water on the SWS. The staff determines that mitigation of MIC buildup had not been effective as indicated by the more than 3-9520 SWS leaks. During the audit and review discussions/interviews, the applicant stated that nobiocides to mitigate MIC had been used in the SWS for many years after initial plant operation.
The lack of aging management for the system manifested itself in 2002 with 20 leaks. The applicant performed a self-assessment of the aging management of the system, including the use of independent industry experts. This resulted in the criteria for the use of biocides to mitigate MIC being revised and the processes for analysis, trending, and interpretation of results being enhanced.The applicant further stated that the improved performance by VYNPS in managing the agingeffects on the SWS after 2002 is demonstrated by the more recent operating experience.
Recent SWS performance test and inspection results from 2004 demonstrated that the program has become more effective in managing aging effects for applicable components. The staff reviewed a sampling of inspection reports and performance testing results for the SWS components and found the documentation to be very detailed and thorough. Since 2002 VYNPS has taken a much more aggressive and pro-active approach to managing the aging effects of the SWS components as indicated by the most recent operating experience where no severe aging was found. The staff finds by VYNPS demonstrating a more pro-active approach to managing aging on the SWS, the type of aggressive aging effects discovered in 2002 will be better managed going forward.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.28, the applicant provided the UFSAR supplement forthe Service Water Integrity Program. The applicant committed (Commitment #45) to implement the enhancement to the ServiceWater Integrity Program to require a periodic visual inspection of the RHRSW pump motor cooling coil internal surface for loss of material by March 21, 2012. The staff reviewed this section and determines that, upon the implementation of Commitment#45, the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Service Water IntegrityProgram, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions, enhancement, and their justifications and determined that the AMP, with the exceptions and enhancement, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately 3-96managed so that the intended function(s) will be maintained consistent with the CLB for theperiod of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.17  Structures Monitoring Program Summary of Technical Information in the Application. LRA Section B.1.27.2 describes theexisting Structures Monitoring Program as consistent, with enhancements, with GALL AMP XI.S6, "Structures Monitoring Program." Structures monitoring in accordance with 10 CFR 50.65 (Maintenance Rule) is addressed inRG  1.160 and NUMARC 93-01. These two documents provide guidance for development of applicant-specific programs to monitor the condition of structures and structural components within the scope of the Maintenance Rule so there is no loss of structure or structural component intended function. Since protective coatings do not manage aging effects for structures included in the Structures Monitoring Program, the program does not address protective coating monitoring and maintenance.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the enhancements to determine whether the AMP, with the enhancements, remained adequate to manage the aging effects for which it is credited.The staff asked the applicant to explain why the inspection of crane rails and girders is notincluded under a program that is consistent with GALL AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems. The applicant stated that its Periodic Surveillance and Preventive Maintenance Program and the Structures Monitoring Program adequately manage aging effects for cranes and girders. Therefore, a separate program (i.e., inspection of overhead heavy load and light load handling system) is not necessary. The staff finds the applicant's response acceptable. The staff asked the applicant to explain if VYNPS has any porous concrete subfoundations anda site dewatering system. In addition, the applicant was asked to explain if the Structures Monitoring Program required periodic sampling and testing of groundwater to determine and confirm that the below grade water chemistry/soil is non-aggressive to concrete structures below grade.The applicant stated that VYNPS does not have porous concrete subfoundations or a sitedewatering system. The results of the two most recent reported groundwater samples as submitted to the State of Vermont were made available to the staff. These samples are currently obtained twice yearly, primarily around the plant septic systems with some of the sampling wells near plant structures. The results of these samples are provided to the State of Vermont in accordance with the Indirect Discharge Permit. The Structures Monitoring Program will be enhanced to ensure an engineering evaluation is made on a periodic basis of groundwater samples to assess for evidence of groundwater being aggressive to concrete. Historically, VYNPS groundwater samples have shown some level of seasonality in that the wells adjacent to roadways have slightly higher levels of chlorides due to salt treatment of roadways in the winter.
3-97In a letter dated July 14, 2006, the applicant stated by amendment to the application that LRASection B.1.27.2 for the Structures Monitoring Program is revised to include an enhancement to perform, at least once every five years, an engineering evaluation of groundwater samples to assess for groundwater being aggressive to concrete.The staff reviewed the applicant's response and finds the applicant's response acceptable. Theapplicant has committed (Commitment #33) to enhancing the VYNPS Structures Monitoring Program to ensure an engineering evaluation is made on a periodic basis of groundwater samples. A five -year periodicity for performing an engineering evaluation of groundwater samples to assess for groundwater being aggressive to concrete has previously been accepted by the staff in other applicant LRAs and therefore on this basis the staff finds the maximum five
-year periodicity acceptable.The staff also asked the applicant to explain if VYNPS will take advantage of inspectionopportunities for structures required for license renewal and identified as inaccessible.The applicant stated that VYNPS will take advantage of inspection opportunities for undergroundstructures that become accessible by excavation. This inspection is already part of the Structures Monitoring Program. The staff finds the applicant's response acceptable. The applicant will take advantage of inspection opportunities for structures required for license renewal and identified as inaccessible.The staff asked the applicant to explain if the inspection acceptance criteria for its StructuresMonitoring Program was based on American Concrete Institute (ACI) standard, ACI 349.3R-96, and if not, to provide the industry codes, standards and guidelines that the acceptance criteria is based on. In addition, the applicant was asked to explain the basis of the acceptance criteria for crane rail/girder inspections.The applicant stated that the VYNPS Structures Monitoring Program is controlled by plantprocedure, as documented in the Audit and Review Report. The standards used to develop and conduct the program are listed in the procedure. The specific standard used to develop inspection requirements for this procedure is NEI 96-03, "Nuclear Energy Institute, Industry Guideline for Monitoring the Condition of Structures at Nuclear Power Plants," Section 3.3,"Examination Guidance." Inspection requirements of commodities taken from NEI-96-03 are delineated in the program procedure. The following comparison of the relevant guidelines for concrete structural components in the program procedure, with the guidelines of ACI 349.3 Chapter 5 "Evaluation Criteria" indicates general consistency:  1)Both documents specify visual inspection methods for the examination of structures. 2)Both documents provide guidance for the inspections for the following parameters andconditions:
* Concrete components: spalling, cracking, delamination, honey combs, waterin-leakage, chemical leaching, peeling paint, or discoloration
* Structure Settlement: excessive total or differential settlement 3-98
* Structural/seismic gap: insufficient space for structural movement during aseismic event (i.e., exclusion of foreign objects or debris); deteriorated elastomer type filler. 3)ACI 349.3R-96 Chapter 5 provides acceptable limits beyond which further evaluation isrequired. PP 7030 Section 4.8 conservatively requires evaluation of identified degradation.Based upon this comparison, the applicant concluded that the guidance for inspections providedin PP 7030 is consistent with the guidelines in ACI 349.3R-96.The acceptance criteria for crane rail/girder inspections are contained in the preventivemaintenance tasks for the crane inspection. A plant procedure provides the inspection and acceptance criteria for crane rail/girders. The procedure criteria is based on the following codes and standards of ANSI B30.2-83 "Overhead and Gantry Cranes" and NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants."The staff reviewed the applicant's response and finds the response acceptable. The applicanthas made a comparison of the VYNPS relevant guidelines for concrete inspection acceptance criteria with the guidelines of ACI 349.3R-96 Chapter 5, and found general consistency. In addition, the applicant stated that the acceptance criteria for crane rail/girder inspections are based on codes and standards of ANSI B30.2-83 and NUREG-0612.The staff noted that the program description in the LRA for the Structures Monitoring Programmakes no reference to GALL AMP XI.S7, "RG 1.127, Inspection of Water-Control Structures Associated With Nuclear Power Plants." GALL AMP XI.S7 stated that for plants not committed to RG 1.127, Revision 1, aging management of water-control structures may be included in the Structures Monitoring Program. However, details pertaining to water-control structures are to incorporate the attributes of GALL AMP XI.S7. During the audit and review, the staff asked the applicant to explain if VYNPS is committed to RG 1.127, Revision 1 for inspection of its water control structures (such as intake structure). If VYNPS is not committed to RG 1.127, Revision 1, explain how the 10 program elements of GALL AMP XI.S7 are incorporated into the VYNPS Structures Monitoring Program.The applicant stated that the water-control structure at VYNPS is the intake structure. There areno earthen water control structures at VYNPS. The program elements of GALL AMP XI.S7 applicable to the intake structure are incorporated in the VYNPS Structures Monitoring Program as described below. Program elements of GALL AMP XI.S7 that are not incorporated in the Structures Monitoring Program primarily apply to earthen structures.1)Scope - The scope of the GALL AMP XI.S7 program applicable toVYNPS is the intake structure. The intake structure is included in the scope of the Structures Monitoring Program as delineated in LRA Table 3.5.2-3.2)Preventive Actions - The GALL AMP XI.S7 program includes nopreventive actions.
3-993)Parameters Monitored - The AERM for concrete structuralcomponents of the intake structure is loss of material which is consistent with the GALL Report, Volume 2 Item II.A6-7. The parameters monitored from the GALL AMP XI.S7 program applicable to loss of material are consistent with those monitored by the Structures Monitoring Program. The guidance for inspections of concrete in RG 1.127, Section C.2, is consistent with the guidance in ACI 349.3R-96 used in the Structures Monitoring Program.4)Detection of Aging - GALL AMP XI.S7 identifies visual inspectionmethods as the primary method used to detect aging. The Structures Monitoring similarly uses visual inspection methods as the primary method used to detect aging in concrete structural components. GALL AMP XI.S7 identifies inspection intervals of five years. The Structures Monitoring Program identifies similar inspection intervals of three years for accessible areas, ten years for inaccessible areas and opportunistic inspections for buried components.5)Monitoring and Trending - Monitoring is by periodic inspection forboth the GALL AMP XI.S7 and Structures Monitoring Programs.6)Acceptance Criteria - Acceptance criteria is not identified inRG 1.127, however appropriate guidance is provided in the Structures Monitoring Program to ensure corrective measures are identified prior to loss of intended function.7-9)The corrective actions, confirmation process and administrativecontrol attributes of the Structures Monitoring Program and the GALL AMP XI.S7 program are consistent.10)Operating Experience - The operating experience relevant to theeffectiveness of the Structures Monitoring Program is presented in Appendix B of the application and is consistent with the operating experience described in GALL AMP XI.S7.The staff reviewed the applicant's response and finds the applicant's response acceptable. Thestaff determines that the applicant has verified that the program elements of GALL AMP XI.S7 pertaining to VYNPS water control structures have been incorporated within the Structures Monitoring Program.The staff reviewed those portions of the Structures Monitoring Program for which the applicantclaimed consistency with GALL AMP XI.S6 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's Structures Monitoring Program provides assurance that the aging of materials of construction, which include structural steel, concrete, roof materials, wood, polyvinyl chloride (PVC), and sealing materials, for structures within the scope of license renewal will be properly managed for the period of extended 3-100operation. The staff finds the applicant's Structures Monitoring Program acceptable because itconformed to the recommended GALL AMP XI.S6, "Structures Monitoring Program," with enhancements.Enhancement 1. In LRA Section B.1.27.2, the applicant stated the following enhancement inmeeting the program element "scope of program." Specifically, the enhancement states:The Structures Monitoring Program will be enhanced to specify that processfacility crane rails and girders, condensate storage tank (CST) enclosure, CO 2tank enclosure, N 2 tank enclosure and restraining wall, CST pipe trench, dieselgenerator cable trench, fuel oil pump house, SW pipe trench, drywell floor liner seal, manway seals and gaskets, and hatch seals and gaskets are included in the program. By letter dated July 14, 2006, as discussed in SER Section 3.0.3.2.17.2, the applicant removedthe drywell floor liner seal from scope of its Structures Monitoring Program since drywell floor liner seal (moisture barrier) is examined in accordance with the its Containment Inservice Inspection-IWE Program.The staff finds that with the addition of the above SCs, the applicant's Structures MonitoringProgram will meet the recommendation of the program described in GALL AMP XI.S6. The applicant identified commitments to the NRC associated with this enhancement relative to GALL AMP XI.S6.On this basis, the staff finds this enhancement (Commitment #20) acceptable since when theenhancement is implemented, the Structures Monitoring Program will be consistent with GALL AMP XI.S6 and will provide additional assurance that the effects of aging will be adequately managed.Enhancement 2. In LRA Section B.1.27.2, the applicant stated the following enhancement inmeeting the program element "detection of aging effects." Specifically, the enhancement states:Guidance for performing structural examinations of wood to identify loss ofmaterial, cracking, and change in material properties will be added to the Structures Monitoring Program.On this basis, the staff finds this enhancement (Commitment #21) acceptable since when theenhancement is implemented, the Structures Monitoring Program will be consistent with GALL AMP XI.S6 and will provide additional assurance that the effects of aging will be adequately managed.Enhancement 3. In LRA Section B.1.27.2, the applicant stated the following enhancement inmeeting the program element "detection of aging effects." Specifically, the enhancement states:Guidance for performing structural examinations of elastomers (Drywell floor linerseal, seals, and gaskets) to identify cracking and change in material properties (cracking when manually flexed) will be enhanced in the Structures Monitoring Program procedure.
3-101On this basis, the staff finds this enhancement (Commitment #22) acceptable since when theenhancement is implemented, the Structures Monitoring Program will be consistent with GALL AMP XI.S6 and will provide additional assurance that the effects of aging will be adequately managed. The drywell floor liner seal is to be removed from scope of the Structures Monitoring Program as discussed in in Enhancement 1.Enhancement 4. In LRA Section B.1.27.2, the applicant stated the following enhancement inmeeting the program element "detection of aging effects." Specifically, the enhancement states:Guidance for performing structural examinations of PVC cooling tower fill toidentify cracking and change in material properties will be added to the Structures Monitoring Program procedure.On this basis, the staff finds this enhancement (Commitment #23) acceptable since when theenhancement is implemented, Structures Monitoring Program," will be consistent with GALL AMP XI.S6 and will provide additional assurance that the effects of aging will be adequately managed.The staff determines that these three enhancements, described above, will provide the inspection methods for SCs that are in-scope of license renewal, to ensure that aging degradation will be detected and quantified before there is loss of intended functions. The staff finds that with the addition of the above guidance for performing structural examinations of wood, elastomers, and PVC cooling tower fill to the Structures Monitoring Program, all the inspection methods for each structure/aging effect combination within the scope of license renewal in accordance with this AMP is provided. The additional guidance provided sufficient detail to ensure that aging degradation will be detected and quantified before there is loss of intended functions.Operating Experience. LRA Section B.1.27.2 states that the concrete pad above John Deerediesel generator day tank was sinking and cracking. The pad was repaired with steel bollards installed to prevent future sinking and cracking. Cooling tower inspections detected degradation of a structural column, cracking of a wooden structural member. The degraded column and associated splice connection were replaced. Resolution of these issues proves that the program is effective for managing cracking of structural components. Recent performance test and inspection results (2002 and 2003) show that the program is effective for managing component aging effects. For example, inspection of the turbine building crane and of the reactor building overhead crane in 2002 revealed no findings; and inspection of the reactor building airlock door seal revealed no cracking, dry rot, bulging, or separation of the seal. The most recent structures monitoring inspection found the overall condition of structures very good. Inspections were conducted in 2004 in the reactor building, turbine building, diesel generator rooms, fuel oil day tank room, control building, plant stack, switch yard, discharge structure, intake structure, and John Deere diesel building. Absence of significant findings during these inspections proves thatthe program is effective for managing loss of material, cracking, and change in material properties for structural components.
3-102The staff reviewed the summary of specific operating experience for the Structures MonitoringProgram. The staff also reviewed the operating experience for a concrete pad sinking and cracking and degradation of a structural wooden column and found that the applicant's existing Structures Monitoring Program was effective in identifying deterioration of plant SCs within its scope. The deficiencies were placed in the CAP for VYNPS and dispositioned for repair. The listed operating experience demonstrated that the VYNPS Structures Monitoring Program is effective in ensuring that age related deterioration of plant SCs within the scope of license renewal is adequately managed to ensure that these SCs maintain their ability to perform their intended function. On the basis of its review, the staff finds that the applicant's Structures Monitoring Program is effective in identifying age-related degradation, implementing repairs, and maintaining the structural integrity of the structures and associated components within the scope of license renewal.The staff also reviewed the operating experience provided in the LRA, and interviewed theapplicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.30, the applicant provided the UFSAR supplement forthe Structures Monitoring Program.The applicant committed (Commitment #20) to enhance the Structures Monitoring Program tospecify that process facility crane rails and girders, CST enclosure, CO 2 tank enclosure, N 2 tankenclosure and restraining wall, CST pipe trench, diesel generator cable trench, fuel oil pump house, SW pipe trench, manway seals and gaskets, and hatch seals and gaskets are included in the program by March 21, 2012.The applicant committed (Commitment #21) to enhance the Structures Monitoring Program toadd guidance for performing structural examinations of wood to identify loss of material, cracking, and change in material, by March 21, 2012.The applicant committed (Commitment #22) in to enhance the Structures Monitoring Program toadd guidance for performing structural examinations of elastomers (seals and gaskets) to identify cracking and change in material properties (cracking when manually flexed) by March 21, 2012.The applicant committed (Commitment #23) to enhance the Structures Monitoring Program toadd guidance for performing structural examinations of PVC cooling tower fill to identify cracking and change in material properties by March 21, 2012.
3-103The applicant committed (Commitment #33) to include in the Structures Monitoring Programprovisions that will ensure an engineering evaluation is made on a periodic basis (at least once every five years) of groundwater samples to assess aggressiveness of groundwater to concrete.
Samples will be monitored for sulfates, pH and chlorides, by March 21, 2012.The staff reviewed this section and determined that, upon the implementation of Commitments#20, #21, #22, #23, and #33, the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Structures MonitoringProgram, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent with the addition of Commitments #20, #21,
#22, #23, and #33. Also, the staff reviewed the enhancements and confirmed that their implementation prior to the period of extended operation would make the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.18  Water Chemistry Control - Closed Cooling Water Program Summary of Technical Information in the Application. LRA Section B.1.30.3 describes theexisting Water Chemistry Control - Closed Cooling Water Program as consistent, with exception,with GALL AMP XI.M21, "Closed-Cycle Cooling Water System." This program includes preventive measures that manage loss of material, cracking, and foulingfor closed cooling water systems (CCWS) (reactor building closed cooling water (CCW), turbine building CCW, augmented off-gas (AOG) CCW, EDG CCW, AOG refrigerant skid water, and chilled water). These chemistry activities monitor and control CCW chemistry using plant-specificprocedures and processes based on EPRI guidance for CCW chemistry.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim ofconsistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the Water Chemistry Control-Closed Cooling WaterProgram for which the applicant claimed consistency with GALL AMP XI.M21 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicant's Water Chemistry Control-Closed Cooling Water Program provided assurance that this program will manage loss of material, cracking, and fouling for the following CCWSs:
* Reactor Building Closed Cooling Water
* Augmented Off-Gas Closed Cooling Water 3-104
* Augmented Off-Gas Refrigerant Skid Water and Chilled Water
* Emergency Diesel Generator Closed Cooling Water
* Turbine Building Closed Cooling WaterThe staff finds the applicant's Water Chemistry Control-Closed Cooling Water Programacceptable because it conformed to the recommended GALL AMP XI.M21, "Closed-Cycle Cooling Water System," with an exception.Exception 1. In LRA Section B.1.30.3, the applicant stated an exception to the GALL Reportprogram element "detection of aging effects." Specifically, the exception states that: The VYNPS Water Chemistry Control-Closed Cooling Water Program does notinclude performance and functional testing. Exception Note
. While GALL AMP XI.M21, Closed-Cycle Cooling Water Systemendorses EPRI Report TR-107396 for performance and functional testing guidance, EPRI Report TR-107396 does not recommend that equipment performance and functional testing be part of a Water Chemistry Control Program. This appears appropriate since monitoring pump performance parameters is of little value in managing effects of aging on long-lived, passive CCWS components. Rather, EPRI Report TR-107396 stated in Section 5.7 (Section 8.4 in EPRI Report 1007820) that performance monitoring is typically part of an engineering program, which would not be part of water chemistry. In most cases, functional and performance testing verifies that component active functions can be accomplished and as such would be included as part of Maintenance Rule (10 CFR 50.65). Passive intended functions of pumps, heat exchangers and other components will be adequately managed by the Closed Cooling Water Chemistry Program through monitoring and control of water chemistry parameters.The staff discussed technical issues related to this exception with the applicant. The applicantstated that aging of CCWS components relies on monitoring and control of CCWS chemistry.
The applicant stated that the effectiveness of the Closed Cooling Water Chemistry Program will be verified by a one-time inspection of the CCWS. The applicant was asked to confirm that the one-time inspection would consider representative sampling of low-flow and stagnant water areas of the listed CCWSs. In its response, the applicant stated that sampling of the entire system, including the piping and fittings, thermowells, and valve bodies in the various systems, would be selected.The staff determines that the applicant would select representative samples from the low-flowand stagnant flow areas of the listed CCWSs in the One-Time Inspection Program, which will provide assurance that the aging effects for this system will be adequately managed. On this basis, the staff finds this exception acceptable.Operating Experience. LRA Section B.1.30.3 states that monthly sample results fromJanuary 2003 through January 2005 showed CCWS chemistry parameters are maintained within EPRI acceptance criteria. Self-assessments in 2000 and 2002 found the program effective at maintaining low levels of contaminants in the water. One reactor building CCW reading for 3-105molybdate corrosion inhibitor was within the EPRI action Level 1 range; the reading was slightlylow, molybdate was added, and the reading returned to normal at the next sample. First and second quarter 2004 reports stated that, "the chemistry of the major CCWSs remains very good and within specification." Sample results within acceptance criteria indicate that the program is effective for managing component loss of material, cracking, and fouling.In addition, self-assessment in 2000 revealed that low triazole concentrations during 1999 wereresolved by the addition of pure 10 percent triazole to CCWSs when molybdate corrosion inhibitor was high and triazole was low. Timely correction of low triazole concentrations provides assurance that the program will ensure adequate water quality to preclude loss of material, cracking, and fouling of applicable components. Self-assessment in 2000 revealed three instances of CCW chemistry outside administrative limits without corrective action taken or planned. Procedural changes and trending process revisions resolved the issue and provide assurance that the program will ensure adequate water quality to preclude component loss of material, cracking, and fouling. A QA audit of program implementation in 2003 found it effective.
QA auditors also confirmed implementation of improvements recommended during previous program audits. A self-assessment in 2002 and a QA audit in 2003 revealed no issues or findings that could impact program effectiveness.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.36, the applicant provided the UFSAR supplement forthe Water Chemistry Control - Closed Cooling Water Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).In addition, in a letter dated January 14, 2007, the applicant provided an amendment to its LRAto explicitly state that the One-Time Inspection Program activities will confirm the effectiveness of the Water Chemistry Control - Closed Cooling Water Program.
Conclusion. On the basis of its audit and review of the applicant's Water ChemistryControl-Closed Cooling Water Program, the staff determines that those program elements, for which the applicant claimed consistency with the GALL Report, are consistent with the GALL Report. In addition, the staff reviewed the exception and the associated justifications, and determines that the AMP, with the exception, is adequate to manage the aging effects for which 3-106it is credited. The staff concludes that the applicant has demonstrated that the effects of agingwill be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.19  Bolting Integrity Program Summary of Technical Information in the Application. In a letter dated October 17, 2006, theapplicant revised its LRA. The applicant submitted its Appendix B, Section B.1.31, "Bolting Integrity Program," and stated its Bolting Integrity Program is a new plant program that is consistent with GALL AMP XI.M18, "Bolting Integrity," with an enhancement. By letter dated January 4, 2007, the applicant provided additional clarification stated:The Bolting Integrity Program applies to bolting and torquing practices ofsafety-related and nonsafety-related bolting for pressure retaining components, nuclear steam supply system (NSSS) support components, and structural joints.
The program addresses all bolting regardless of size (except the reactor vessel closure studs which are addressed by the Reactor Vessel Closures Stud Program). The applicant stated that this program relies on recommendations for a comprehensive boltingintegrity program as delineated in NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants," and industry recommendations as delineated in the EPRI NP-5769, with the exceptions noted in NUREG-1339 for safety-related bolting. The program relies on industry recommendations for comprehensive bolting maintenance as delineated in EPRI TR-104213 for pressure-retaining bolting and structural bolting.The applicant stated that this program covers bolting within the scope of license renewal,including: (1) safety-related bolting, (2) bolting for NSSS component supports, (3) bolting for other pressure-retaining components including nonsafety-related bolting, and (4) structural bolting (actual measured yield strength is less than or equal to 150 ksi). The aging management of reactor head closure studs is addressed by GALL AMP XI.M3 and is not included in this program. The staff's recommendations and guidelines for comprehensive bolting integrity programs that encompass all safety-related bolting are delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI. The industry's technical basis for the program for safety-related bolting and guidelines for material selection and testing, bolting preload control, ISI, plant operation andmaintenance, and evaluation of the structural integrity of bolted joints is outlined in EPRI NP-5769, with the exceptions noted in NUREG-1339. For other bolting, this information is set forth in EPRI TR-104213.The applicant also stated that its Bolting Integrity Program applies to bolting and torquingpractices of safety-related and nonsafety-related bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all bolting regardless of size. Guidance for the program is contained in NUREG-1339, which refers to EPRI NP-5769 and EPRI NP-5067 for technical bases. For other (structural) bolting, the guidelines of EPRI TR-104213 are followed.
3-107Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The Audit and Review Report details the staff's audit evaluation of this AMP. The staff reviewed the exception and the associated justifications to determine whether the AMP, with the exception, remains adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the Bolting Integrity Program for which the applicant claimsconsistency with GALL AMP XI.M18 and found that they are consistent with the GALL AMP. On the basis of its review, the staff concludes that the applicant's Bolting Integrity Program will adequately manage the aging effects associated with the bolting. The staff finds the applicant's Bolting Integrity Program conforms to the recommended GALL AMP XI.E4, "Bolting Integrity,"
with the enhancement as described below.Enhancement. The applicant stated the following enhancement in meeting the program element"preventive actions." Specifically, the enhancement states:Enhance procedures to clarify that actual yield strength is used in selectingmaterials for low susceptibility to SCC.The staff finds that this enhancement ensures that the recommendations in the referenceddocuments are properly implemented. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented, the Bolting Integrity Program will be consistent with GALL AMP XI.M18, and will provide additional assurance that the effects of aging will be adequately managed.Operating Experience. The applicant stated that operating experience reviews did not identifycracking or loss of preload as AERMs for pressure boundary bolting. Although cracking and loss of preload are not AERMs for the plant equipment operator, plant procedures implement the recommendations of NUREG-1339, "Resolution to Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants," for pressure boundary bolting in the scope of license renewal. Plant procedures address material and lubricant selection, design standards, and good bolting maintenance practices in accordance with EPRI 5067, "Good Bolting Practices."The staff reviewed the operating experience provided in the LRA supplement and interviewedthe applicant's technical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10.
The staff finds this program element acceptable.
3-108UFSAR Supplement. The applicant provided the UFSAR supplement for the Bolting IntegrityProgram.The applicant committed (Commitment #34) to implement the Bolting Integrity Program byMarch 21, 2012.The staff reviewed the UFSAR Supplement section and determines that, upon implementation ofCommitment #34, the information in the UFSAR supplement provided an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Bolting Integrity Program, thestaff determines that those program elements, for which the applicant claimed consistency with the GALL Report, are consistent with the addition of Commitment # 34. Also, the staff reviewed the enhancement and confirmed that the implementation of the enhancements prior to the period of extended operation would result in the existing AMP being consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.20  Metal-Enclosed Bus Inspection Program Summary of Technical Information in the Application. In a letter dated October 17, 2006, theapplicant revised its LRA. The applicant submitted its Appendix B, Section B.1.32, and stated that the Metal-Enclosed Bus Inspection Program is a new program that will be comparable to GALL AMP XI.E4, "Metal-Enclosed Bus," with exceptions. The applicant stated that in accordance with Metal-Enclosed Bus Inspection Program, internalportions of the isophase bus which runs between the main transformer and the unit auxiliary transformer are inspected for cracks, corrosion, foreign debris, excessive dust buildup, and evidence of water intrusion. Internal bus supports are inspected for structural integrity and signs of cracks. Enclosure assemblies are visually inspected for evidence of loss of material and, where applicable, enclosure assembly elastomers are inspected to manage cracking and change in material properties.Staff Evaluation. The staff confirmed the applicant's claim of consistency with the GALL Report.The Audit and Review Report details the staff's audit evaluation of this AMP. The staff reviewed the enhancements and the associated justifications to determine whether the AMP, with the exceptions, remains adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the applicant's Metal-Enclosed Bus Inspection Program forwhich the applicant claims comparable with GALL AMP XI.E4 and found that they are consistent with the GALL Report AMP. On the basis of its review, the staff concludes that the applicant's Metal-Enclosed Bus Inspection Program will adequately manage the aging effects associated with the metal-enclosed bus (MEB). The staff finds the applicant's Metal-Enclosed Bus Inspection Program conforms to the recommended GALL AMP XI.E4, "Metal-Enclosed Bus,"
with the exceptions.
3-109Exception 1. In the revised LRA Section B.1.32, the applicant stated an exception to the GALLReport program elements "parameters monitored/inspected" and "detection of aging effects."
Specifically, the exception states that: MEB enclosure assemblies will be inspected in addition to internal surfaces. The applicant stated that MEB enclosure assemblies will be inspected in addition to internalsurfaces. The applicant also stated that, in accordance with Exception Note 1, that inspection ofMEB enclosure assemblies in accordance with its Metal Enclosure Bus Inspection Program assures that effects of aging will be identified prior to loss of intended functions. The staff reviewed the applicant's Metal Enclosure Bus Program and found that the inspectionproposed by the applicant is consistent with the inspection portion of GALL AMP XI.S6. The applicant will inspect the external surfaces of MEB enclosure assemblies, including enclosure assembly elastomers, for cracking and change in material properties. On this basis, the staff finds this exception acceptable.Exception 2. In revised LRA Section B.1.32, the applicant stated an exception to the GALLReport program elements "parameters monitored/inspected" and "detection of aging effects."
Specifically, the exception states that: Bus insulation will not be inspected or monitored since the isophase bus whichruns between the main transformer and the unit auxiliary transformer does not have bus insulation.The staff reviewed the applicant's Metal-Enclosed Bus Inspection Program. The staff finds thatsince the design of VYNPS isophase bus is different from non-segregated phase bus in that it does not have insulation material on the isophase bus, there is no need for inspecting or monitoring bus insulation. On this basis, the staff finds this exception acceptable. Operating Experience. In the revised LRA, the applicant stated that its Metal-Enclosed BusInspection Program is a new program. The program is based on the program described in NUREG-1801 which in turn is based on industry operating experience. Industry operating experience and plant operating experience will be considered during program implementation. The staff reviewed the operating experience at VYNPS and finds that operating experience atVYNPS is controlled by procedure. The program includes the following components: (1)
Operating Experience - Information received from various industry sources that describes events, issues, equipment failures, that may represent opportunities to apply lessons learned to avoid negative consequences or to recreate positive experience as applicable; (2) Internal Operating Experience - Operating experience (OE) that originates as a condition report or request from plant personnel which warrants consideration for possible Entergy-wide distribution.Internal operating experience can originate from any Entergy plant or headquarters; and (3)
Impact Evaluation - Analysis of an operating experience event or problem that requires additional information and research to determine impact or potential impact, as it relates to plant condition and/or configuration. An impact evaluation is typically documented with a condition report. Condition report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed.
3-110The staff reviewed the operating experience provided in the revised LRA, and interviewed theapplicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.UFSAR Supplement. In revised LRA Section A.2.1.38, the applicant provided the UFSARsupplement for the Meta-Enclosed Bus Inspection Program.The applicant committed (Commitment #32) to implement the Metal-Enclosed Bus Program byMarch 21, 2012.The staff reviewed LRA Section A.2.1.38 and determines that, upon implementationCommitment #32, the information in the UFSAR supplement provided an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Metal-Enclosed BusInspection Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent with the addition of Commitment # 32.
In addition, the staff reviewed the exceptions and the associated justifications, and determines that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.3  AMPs Not Consistent with or Not Addressed in the GALL ReportIn LRA Appendix B, the applicant identified the following AMPs as plant-specific:
* Heat Exchanger Monitoring Program
* Containment Inservice Inspection Program
* Inservice Inspection Program
* Instrument Air Quality Program
* Periodic Surveillance and Preventive Maintenance Program
* Vernon Dam Federal Energy Regulatory Commission Inspection
* Water Chemistry Control - Auxiliary Systems ProgramFor AMPs not consistent with or not addressed in the GALL Report, the staff performed acomplete review to determine their adequacy to monitor or manage aging. The staff's review of these plant-specific AMPs is documented in the following sections.
3-1113.0.3.3.1  Heat Exchanger Monitoring ProgramSummary of Technical Information in the Application. LRA Section B.1.14 describes the HeatExchanger Monitoring Program as a new, plant-specific program. The Heat Exchanger Monitoring Program will inspect heat exchangers for degradation and, iffound, evaluate its effects on the heat exchanger's design functions, including ability to withstand a seismic event. Representative tubes within the sample population of heat exchangers will be eddy current-tested at a frequency determined by plant-specific and industry operating experience to identify aging effects prior to loss of intended function. With each eddy current test, visual inspections on accessible heat exchanger heads, covers and tube sheets will monitor surface conditions for indications of loss of material. The sample population of heat exchangers includes the high-pressure coolant injection (HPCI) gland seal condenser (GSC), HPCI lube oilcooler, reactor core isolation coolant lube oil cooler, condensate storage and transfer steam reheat coil, drywell atmospheric cooling units (RRU-1, 2, 3, and 4), reactor recirculation pump (RRP) seal water coolers, RRP motor upper and lower bearing oil coolers, and RRP motor air coolers. The program will be implemented prior to the period of extended operation.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information inLRA Section B.1.14 on the applicant's demonstration of the Heat Exchanger Monitoring Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation.The staff reviewed the Heat Exchanger Monitoring Program against the AMP elements found inthe GALL Report, in SRP-LR Appendix A.1.2.3, and in SRP-LR Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 elements (i.e.,
"scope of the program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance criteria," "corrective actions,"
"confirmation process," "administrative controls," and "operating experience").The applicant indicated that the "corrective actions," "confirmation process," and "administrativecontrols" program elements are parts of the site-controlled QA program. The staff's evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven elements follows:  (1)Scope of Program - LRA Section B.1.14 states that this program will manage agingeffects on selected heat exchangers in various systems as identified in AMRs. In the program description for this program in the LRA, the applicant listed the specific components that are managed by this program.The staff confirmed that the specific components for which the program manages agingeffects are identified by the applicant, which satisfies the criterion as defined in SRP-LR Appendix A.1.2.3.1. On this basis, the staff finds that the applicant's proposed program scope acceptable.The staff confirmed that the "scope of the program" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff finds this program element acceptable.
3-112  (2)Preventive Actions - LRA Section B.1.14 states that this program is an inspectionprogram and no actions are taken as part of this program to prevent degradation.The staff confirmed that the preventive actions program element satisfied the criteriadefined in SRP-LR Appendix A.1.2.3.2. The staff finds it acceptable because this is an inspection program and there is no need for preventive actions. On this basis, the staff finds that the applicant's preventive actions acceptable.The staff confirmed that the "preventive actions" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.2. The staff finds this program element acceptable.  (3)Parameters Monitored or Inspected - LRA Section B.1.14 states that this program wherepractical, eddy current inspections of shell-and-tube heat exchanger tubes may be performed to determine tube wall thickness. Visual inspections will be performed on heat exchanger heads, covers and tube sheets where accessible to monitor surface condition for indications of loss of material.The staff confirmed that the preventive actions program element satisfied the criteriadefined in SRP-LR Appendix A.1.2.3.3. In the LRA, the applicant stated that this AMP is credited to manage the aging effect of loss of material on the pressure boundary intended function for the components for which this AMP is credited. Visual inspection of the heat exchanger heads, covers and tube sheets is capable of detecting indications of loss of material. The use of eddy current testing of the shell-and-tube heat exchanger tubes to determine changes in tube wall thickness will detect the loss of material on the tubes. On this basis, the staff finds that the applicant's description of the parameters monitored/inspected is acceptable.The staff confirmed that the "parameters monitored or inspected" program elementsatisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.3. The staff finds this program element acceptable.  (4)Detection of Aging Effects - LRA Section B.1.14 states that loss of material is the agingeffect managed by this program. Representative tubes within the sample population of heat exchangers will be eddy current tested at a frequency determined by internal and external operating experience to ensure that effects of aging are identified prior to loss of intended function. Visual inspections of accessible heat exchangers will be performed on the same frequency as eddy current inspections.In addition, as stated in the LRA, supplement dated March 23, 2007, an appropriatesample population of heat exchangers will be determined based on operating experience prior to inspections. The sample population of heat exchangers will be determined based on materials of construction of the heat exchanger tubes and the associated environments as well as the type of heat exchanger (for example, shell and tube type). At least one heat exchanger of each type, material and environment combination will be included in the sample population. Inspection can reveal loss of material that could result in degradation of the heat exchangers. Fouling is not addressed by this program.
3-113The LRA supplement also stated that testing frequency will be established using baselineeddy current testing in accordance with industry best practices and EPRI recommendations. The results of these baseline tests will be used to determine the frequency of future inspections and the number of tubes to be sampled. Additional examination methods (e.g., ultrasonic thickness measurements or radiography) may be used if "as-found" conditions warrant. The results of these inspections will be used to establish the frequency of future inspections.As documented in the Audit and Review Report, the applicant clarified that all heatexchangers in the program are inspected. The population of tubes for eddy-current testing is sampled using a standard industry methodology. The applicant also indicated that the heat transfer intended function is managed in accordance with another program for those heat exchangers for which this function is required.The inspection for the aging effect of loss of material is directly related to the pressureboundary intended function. All of the heat exchangers in the program are to be inspected and any sampling of the tubes to be selected for eddy-current testing is based on an industry standard methodology. The sample population of tubes will be eddy-current tested at a frequency based on internal and external operating experience.
On this basis, the staff finds that the applicant's description of the detection of aging effects is acceptable.The staff confirmed that the "detection of aging effects" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.4. The staff finds this program element acceptable.  (5)Monitoring and Trending - LRA Section B.1.14 states that results of this program will beevaluated against established acceptance criteria and an assessment will be made regarding the applicable degradation mechanism, degradation rate and allowable degradation level. This information will be used to develop future inspection scope and to modify inspection frequency, if appropriate. Wall thickness will be trended and projected to the next inspection. Corrective actions will be taken if projections indicate that the acceptance criteria may not be met at the next inspection.The staff confirmed that the monitoring and trending program element satisfied thecriteria defined in SRP-LR Appendix A.1.2.3.5. The program described above provides for monitoring and trending the eddy-current thickness data. In addition, the applicant stated that the condition of the surfaces based on visual inspections of the heat exchanger heads, covers and tube sheets will be trended. This information will allow the applicant to take the appropriate corrective actions before the loss of intended function.
On this basis, the staff finds that the applicant's description of monitoring and trending is acceptable.The staff confirmed that the "monitoring and trending" program element satisfiesrecommendation defined in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.5. The staff finds this program element acceptable.
3-114  (6)Acceptance Criteria - LRA Section B.1.14 states that the minimum acceptable tube wallthickness for each heat exchanger to be eddy current inspected will be established based upon a component-specific engineering evaluation that considers industry best practices and EPRI recommendations. Wall thickness will be acceptable if greater than the minimum wall thickness for the component.In addition, as stated in the LRA, the acceptance criterion for visual inspections of heatexchanger heads, covers and tubesheets will be no evidence of degradation that could lead to loss of intended function. If degradation that could lead to loss of intended function is detected, a condition report will be written and the issue resolved in accordance with the site CAP.The staff confirmed that the acceptance criteria program element satisfied the criteriadefined in SRP-LR Appendix A.1.2.3.6. The staff finds the use of specific criteria for the minimum wall thickness for each component based on a component-specific engineering evaluation to be acceptable for the eddy-current testing. On this basis, the staff finds that the applicant's description of the acceptance criteria is acceptable.The staff confirmed that the "acceptance criteria" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.6. The staff finds this program element acceptable.
 
  (10)Operating Experience - LRA Section B.1.14 states that there is no operating experiencefor the new Heat Exchanger Monitoring Program.The staff recognized that the CAP, which captures internal and external plant operatingexperience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation defined in the GALL Report and in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.15, the applicant provided the UFSAR supplement forthe Heat Exchanger Monitoring Program.The applicant committed to implement the Heat Exchanger Monitoring Program, documented asCommitment #12, as described in VYNPS AMP B.1.14, by March 21, 2012.The staff reviewed this section and determined that, upon the implementation of Commitment#12, the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its technical review of the applicant's Heat Exchanger MonitoringProgram with the addition of Commitment #12, the staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as 3-115required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for thisAMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.3.2  Containment Inservice Inspection Program Summary of Technical Information in the Application. LRA Section B.1.15.1 describes theContainment Inservice Inspection Program, as an existing, plant-specific program.Section 50.55a of 10 CFR imposes ASME Code, Section XI, ISI requirements for Classes 1, 2,and 3 pressure-retaining components and their attachments in light-water cooled power plants.
Additionally, 10 CFR 50.55a imposes ASME Code, Section XI, ISI requirements for Class MC and Class CC containment structures. Subsection IWE provides inspection requirements for Class MC metal containments and Class CC concrete containments. The scope of Subsection IWE includes steel liners for concrete containment and their attachments, containment hatches and airlocks, moisture barriers, and pressure-retaining bolting. The program uses NDE techniques to detect and characterize flaws. Three different types of examinations are volumetric, surface, and visual. Volumetric examinations are the most extensive, using methods such as radiographic, ultrasonic or eddy current examinations to locate surface and subsurface flaws. Surface examinations, such as magnetic particle or dye penetrant testing, are used to locate surface flaws. Three levels of visual examinations are specified: VT-1, VT-2, and VT-3.The Containment Inservice Inspection Program encompasses the requirements for theinspection of Class MC pressure-retaining components (primary containment) and their integral attachments in accordance with the requirements of 10 CFR 50.55a(b)(2) and the 1998 Edition of ASME Code, Section XI with 2000 Addenda, Inspection Program B.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information inLRA Section B.1.15.1 on the applicant's demonstration of the Containment Inservice Inspection Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation.The staff reviewed the Containment Inservice Inspection Program against the AMP elementsfinds in the GALL Report, in SRP-LR Appendix A.1.2.3, and in SRP-LR Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 elements (i.e.,
"scope of the program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance criteria," "corrective actions,"
"confirmation process," "administrative controls," and "operating experience").During the audit and review, the staff asked the applicant to explain why its ContainmentInservice Inspection Program was a plant-specific program instead of an existing plant program that is consistent with GALL AMP XI.S1, "ASME Code, Section XI, Subsection IWE," with exceptions. The applicant stated that VYNPS chose to describe its Containment Inservice Inspection Program as plant-specific rather than comparing it to the corresponding GALL Report program because the GALL Report program contains many ASME Code, Section XI tables and section numbers which change with different versions of the code. Because of this, comparison with the GALL Report program would have generated many exceptions and explanations which 3-116would have detracted from the objective of the comparison. Therefore, the Inservice Inspection -Containment Inservice Inspection Program was presented as a plant-specific program so that it could be evaluated on its own merit without numerous explanations of code revision. The staff finds VYNPS's classification of its Containment Inservice Inspection Program as plant-specific an acceptable alternative to characterizing it as consistent with GALL AMP XI.S1, with exceptions.The staff's evaluation of the 10 program element are provided below. The staff's evaluation ofthe applicant's QA program is discussed in SER Section 3.0.4.  (1)Scope of Program - LRA Section B.1.15.1 states that this program, in accordance withASME Code, Section XI Subsection IWE, manages loss of material and cracking for the primary containment and its integral attachments. The primary containment is a GE Mark I pressure suppression containment system. The system consists of a drywell (housing the reactor vessel and reactor coolant recirculation loops), a pressure suppression chamber (housing a water pool), and the connecting vent system between the drywell and the water pool, isolation valves, and containment cooling systems. The code of construction for the containment structure is the ASME Code, Section III,1965,with winter addenda.The staff confirmed that the specific components for which the program manages agingeffects are identified by the applicant, which satisfied the criterion as defined in SRP-LR Appendix A.1.2.3.1. On this basis, the staff finds that the applicant's proposed program scope acceptable.The staff confirmed that the "scope of the program" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff finds this program element acceptable.  (2)Preventive Actions - LRA Section B.1.15.1 states that this program is a monitoringprogram that does not include preventive actions.The staff confirmed that the preventive actions program element satisfied the criteriadefined in SRP-LR Appendix A.1.2.3.2. The staff finds that the applicant's Containment Inservice Inspection Program is only an inspection program and the inspections performed in accordance with this program will only monitor the condition of the primary containment and its integral attachments and will not perform any preventive or mitigating action for aging effects/mechanisms. On this basis, the staff finds the applicant's preventive actions acceptable.The staff confirmed that the "preventive actions" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.2. The staff finds this program element acceptable.  (3)Parameters Monitored or Inspected - LRA Section B.1.15.1 states that the primarycontainment and its attachments are inspected for evidence of cracks, wear, and
 
corrosion.
3-117The staff asked the applicant to explain why VYNPS did not have a Service Level IProtective Coating Monitoring and Maintenance Program to prevent coating failure that could adversely affect the operation of post-accident fluid systems emergency core cooling systems (ECCS) and thereby impair safe shutdown. The applicant had already stated in the LRA that coatings are not relied on for managing aging effects for license renewal which the staff finds acceptable. The applicant stated in detail during the audit and review its response to GL 98-04, "Potential for Degradation of the Emergency Core Cooling System and Containment Spray System After a Loss of Coolant Accident Because of Construction and Protective Coating Deficiencies and Foreign Material in Containment," dated July 14, 1998, that the impact of debris loading on the ECCS strainers at VYNPS is discussed. As discussed in the GL response, in response to NRC Bulletin 96-03, new large passive ECCS strainers have been installed at VYNPS. The applicant stated that the new VYNPS torus strainers were designed to accept 100 percent of the coatings within the LOCA pipe break steam/water jet zone of influence.
The approach velocity of materials entrained in the torus water is extremely low due to the sizing of the ECCS strainers and also any coating debris would quickly settle to the bottom of the suppression pool after the initial turbulence subsided.The NRC has previously accepted VYNPS's response to GL 98-04 which indicated thatthe coatings of the containment will not affect the operation of the ECCS strainers during a LOCA. Since coatings are not relied upon to manage aging effects and not an ECCS strainer blockage concern, the staff finds the applicant's response acceptable for not requiring a Service Level I Protective Coating Monitoring and Maintenance Program in accordance with license renewal.The staff confirmed that the parameters monitored/inspected program element satisfiesthe criteria defined in SRP-LR Appendix A.1.2.3.3. The staff finds that the applicant has identified the parameters of the primary containment and its attachments which need to be inspected by general visual examination to determine if aging effects/mechanisms have occurred and to the extent that detailed visual examinations need to be performed.
In accordance with IWE requirements, if detailed IWE visual examinations are required of certain areas, the areas shall be examined for evidence of cracking, discoloration, wear, pitting, excessive corrosion, gouges, surface discontinuities, dents, and other signs ofsurface irregularities. On this basis, the staff finds that the applicant's description of the parameters monitored or inspected acceptable.The staff confirmed that the "parameters monitored or inspected" program elementsatisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.3. The staff finds this program element acceptable.
3-118  (4)Detection of Aging Effects - LRA Section B.1.15.1 states that this program manages lossof material for the primary containment and its integral attachments. In addition, as stated in the LRA, the primary inspection method for the primary containment and its integral attachments is visual examination. Visual examinations are performed either directly orremotely with sufficient illumination and resolution suitable for the local environment to assess general conditions that may affect either the containment structural integrity or leak tightness of the pressure retaining component. The program includes augmented ultrasonic exams to measure wall thickness of the containment structure.The staff confirmed that this program element satisfies the criteria defined in SRP-LRAppendix A.1.2.3.4. Although not stated in accordance with this element, the staff finds that the applicant has identified the frequency of inspections in accordance with the program description. In accordance with the program description, it is stated that VYNPS uses Inspection Program B of ASME Code, Section XI Subsection IWE. This inspection program consists of sequential 10-year inspection intervals with three partial inspection periods within the interval. All accessible areas of the primary containment and its integral attachments will be inspected every 10 years. An initial visual examination is an adequate method to gather data on the condition of the primary containment and its integral attachments. Should flaws or areas of degradation be found which exceed the acceptance standards, ultrasonic examinations are also an adequate method to determine remaining component thickness. On this basis, the staff finds that the applicant's description of the detection of aging effects acceptable.The staff confirmed that the "detection of aging effects" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.4. The staff finds this program element acceptable.  (5)Monitoring and Trending - LRA Section B.1.15.1 states that program results arecompared, as appropriate, to baseline data and other previous test results. If indications are accepted for continued use by analytical evaluation, the areas containing such flawsare monitored during successive inspection periods.The staff confirmed that for visual inspection, this program element satisfies the criteriadefined in SRP-LR Appendix A.1.2.3.5. The staff finds that the applicant will retain all inspection results and records in accordance with its Inservice Inspection - Containment Inservice Inspection Program. As appropriate, reviews of previous inspection results and records will be done for areas containing flaws so that long-term degradation can be trended. The applicant will continue to monitor areas containing flaws during successive inspection periods even if the flaws are accepted for continued use by analytical evaluation. On this basis, the staff finds that the applicant's description of the monitoring and trending acceptable.The staff confirmed that the "monitoring and trending" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.5. The staff finds this program element acceptable.
3-119  (6)Acceptance Criteria - LRA Section B.1.15.1 states that program results are compared, asappropriate, to baseline data, other previous test results, and acceptance criteria of the ASME Code, Section XI, Subsection IWE for evaluation of any evidence of degradation.The staff confirmed that the acceptance criteria program element satisfied the criteriadefined in SRP-LR Appendix A.1.2.3.6. The staff finds that the applicant compared all primary containment and its integral attachments inspection findings, as appropriate, to baseline data, other previous test results, and acceptance criteria of the ASME Code, Section XI, Subsection IWE. On this basis, the staff finds that the applicant's description of the acceptance criteria acceptable.The staff confirmed that the "acceptance criteria" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.6. The staff finds this program element acceptable.  (7)Corrective Actions - The adequacy of the applicant's 10 CFR 50, Appendix B Programassociated with this program element is reviewed by the staff and addressed in SER Section 3.0.4.The staff reviewed other aspects of this program element to determine whether or not itsatisfied the criteria defined in SRP-LR Appendix A.1.2.3.7. The staff finds that the applicant will take corrective action when conditions adverse to the quality of the primary containment and its integral attachments exist, by performing evaluations and/or repair and replacements. On this basis, the staff finds that the applicant's description of the corrective actions acceptable.  (8)Confirmation Process - The adequacy of the applicant's 10 CFR 50, Appendix B Programassociated with this program element was reviewed by the staff and is addressed in SER Section 3.0.4.The staff reviewed other aspects of this program element to determine whether or not itsatisfied the criteria defined in SRP-LR Appendix A.1.2.3.8. The staff finds that the applicant's confirmation process is part of the CAP and included reviews to assure that proposed actions are adequate, tracking and reporting of open corrective actions, and review of corrective action effectiveness. Any followup inspection required by the confirmation process is documented in accordance with the CAP. The CAP constitutes the confirmation process for the VYNPS AMPs and activities. The ASME Code, Section XI, Subsection IWE, also requires that when the primary containment and its integral attachments examination results require evaluation of flaws or areas of degradation, and the component is acceptable for continued service, the areas containing such flaws or areas of degradation shall be reexamined during the next inspection period in accordance with augmented inspections. In accordance with Subsection IWE, when the reexaminations reveal that the flaws or areas of degradation remain essentially unchanged for the next inspection period, these areas no longer require augmented examination. On this basis, the staff finds that the applicant's description of the confirmation process acceptable.
3-120  (9)Administrative Controls - The adequacy of the applicant's 10 CFR 50, Appendix BProgram associated with this program element was reviewed by the staff and is addressed in SER Section 3.0.4.The staff reviewed other aspects of this program element to determine whether or not itsatisfied the criteria defined in SRP-LR Appendix A.1.2.3.9. The staff finds that the applicant's Containment Inservice Inspection Program has regulatory and administrative controls which provide a formal review and approval process of the program. On this basis, the staff finds that the applicant's description of the administrative controls acceptable.  (10)Operating Experience - LRA Section B.1.15.1 states that RFO 21 inspections finds onlytwo areas of potential age-related degradation; the drywell floor to metal containment moisture barrier had missing paint, cracked paint, and areas of corrosion on the base metal in the seal area; and corrosion was found in the area of the X-5G penetration.
Engineering evaluation was performed and no significant wall loss was identified. Base metal was prepared, primed and painted to protect it from further corrosion, and the moisture barrier was replaced. RFO 22 inspections found two more areas of potential age-related degradation; surface pitting of primary containment vent headers and vent pipe bowls; and corrosion on torus penetrations X-207A-H. Evaluation determined that the components have significant margin to code minimum wall thickness and that the rate of corrosion is low due to the inerted containment environment during operation.
Augmented inspections were not necessary since none of the identified corrosion was significant. RFO 24 inspections revealed flaking coating and rust staining on the bay 3 inner torus wall. Subsequent ultrasonic examination revealed no material loss. Also,visual inspection of drywell head exterior surface revealed areas of localized missing coating and primer with light corrosion, but no material loss. Resolution of these issues prior to loss of component intended function proves that the program is effective at managing aging effects for primary containment and its integral attachments. RFO 24 visual inspections of drywell interior surfaces, stabilizer assembly interior surfaces, torus penetrations, and drywell penetrations revealed areas of localized missing coating where the primer is intact, but no corrosion or material loss. Visual inspection of new drywell moisture barrier resulted in no recordable indications. Absence of aging effects on these components proves that the program is effective at managing aging effects for primary containment and its integral attachments.Further, QA surveillance during RFO 24 revealed a problem with program administrativecontrols. The issue was addressed and closed. The program was revised to require that engineering evaluations of indications that do not meet acceptance criteria be completed before the containment is declared operable. QA surveillance revealed an issue that could impact effectiveness of the program. Resolution of this issue provides evidence that the program remains effective at managing aging effects for primary containment and its integral attachments. A recent engineering system health report revealed no issues or findings that could impact program effectiveness.
3-121The staff reviewed the summary of specific operating experience provided in theapplicant's applicable program basis document, as documented in the Audit and Review Report, for the Containment Inservice Inspection Program. The review indicated that the applicant's Inservice Inspection - Containment Inservice Inspection Program is effective in identifying age-related degradation, implementing repairs, and maintaining the integrity of the containment pressure boundaries and the moisture barrier seal.The staff noted that there has been only one noteworthy component CR written as aresult of the Inservice Inspection - Containment Inservice Inspection Program since the inception of the program. During the RFO 21 inspections, two areas of potential age-related degradation were discovered. The drywell floor to metal containment moisture barrier had missing paint, cracked paint, and areas of corrosion on the base metal in the seal area; and corrosion was found in the area of the X-5G penetration. The applicant performed an engineering evaluation and no significant wall thickness loss was identified. The applicant prepared, primed and painted the containment base metal to protect it from further corrosion, and the moisture barrier was replaced. Historically, the other deficiencies were limited to such things as flaking or missing coatings on the drywell liner, minor rust staining and corrosion of the drywell liner, and minor corrosion of drywell penetrations, torus penetrations, vent headers, vent pipe bowls, drywell head and torus bays. None of these deficiencies resulted in loss of intended function due to age-related degradation. This provides assurance that containment pressure boundary degradation has not been occurring since the inception of the program.The staff also noted that there was one noteworthy CR written by the applicant's QA on adeficiency in the process for declaring the containment operable after a RFO. QA surveillance during RFO 24 revealed a problem with the Inservice Inspection -
Containment Inservice Inspection Program administrative controls that could have impacted the effectiveness of the program. The applicant states in the LRA that the program was revised to require that engineering evaluations of indications that do not meet acceptance criteria be completed before the containment is declared operable. The staff finds that the applicant's resolution of this issue ensures that the containment pressure boundary will not operate in a condition with findings that have not been evaluated.The staff reviewed the operating experience provided in the LRA, and interviewed theapplicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable.
3-122UFSAR Supplement. In LRA Section A.2.1.16, the applicant provided the UFSAR supplement forthe Containment Inservice Inspection Program. The staff reviewed LRA Section A.2.1.16 and finds the UFSAR supplement information an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its technical review of the applicant's Containment InserviceInspection Program, the staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.3.3  Inservice Inspection Program Summary of Technical Information in the Application. LRA Section B.1.15.2 describes theInservice Inspection Program, as an existing, plant-specific program.Section 50.55a of 10 CFR imposes inservice inspection requirements of ASME Code Section XIfor Classes 1, 2, and 3 pressure-retaining components and their attachments in light-water cooled power plants. Additionally, 10 CFR 50.55a imposes inservice inspection requirements of ASME Code Section XI for Class MC and Class CC containment structures. Subsection IWE contains inspection requirements for Class MC metal containments and Class CC concrete containments. The scope of IWE includes steel liners for concrete containment and their attachments; containment hatches and airlocks; moisture barriers; and pressure-retaining bolting. The program uses NDE techniques to detect and characterize flaws. Three different types of examinations are volumetric, surface, and visual. Volumetric examinations are the most extensive, with such methods as radiographic, ultrasonic, or eddy current examinations to locate surface and subsurface flaws. Surface examinations like magnetic particle or dye penetrant testing locate surface flaws. Three levels of visual examinations specified are VT-1, VT-2, and VT-3.The Inservice Inspection Program encompasses ASME Code, Section XI, Subsection IWA, IWB,IWC, IWD and IWF requirements. The Inservice Inspection Program is based on ASME Code, Inspection Program B (IWA-2432), which has 10-year inspection intervals. Every 10 years the program is updated to the latest ASME Code edition and addendum, Section XI, approved by the staff, in accordance with 10 CFR 50.55a. On September 1, 2003, VYNPS entered the fourth ISI interval. The Code Edition and Addenda used for the fourth interval is the 1998 Edition with 2000 Addenda. The current program maintains the structural integrity of Classes 1, 2, and 3 systems and supports at the level required by 10 CFR 50.55a.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information inLRA Section B.1.15.2 on the applicant's demonstration of the Inservice Inspection Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation.
3-123The staff reviewed the Inservice Inspection Program against the AMP elements found in theGALL Report, in SRP-LR Appendix A.1.2.3, and in SRP-LR Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 elements (i.e., "scope of the program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance criteria," "corrective actions," "confirmation process," "administrative controls," and "operating experience").The applicant indicated that the "corrective actions," "confirmation process," and "administrativecontrols" program elements are parts of the site-controlled QA program. The staff's evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven elements follows:  (1)Scope of Program - LRA Section B.1.15.2 states that this program manages cracking,loss of material, and reduction of fracture toughness of reactor coolant system piping, components, and supports. The program implements applicable requirements of ASME Code, Section XI, Subsections IWA, IWB, IWC, IWD and IWF, and other requirements specified in 10 CFR 50.55a with approved NRC alternatives and relief requests. Every 10 years the Inservice Inspection Program is updated to the latest ASME Code Edition and Addendum, Section XI, approved by the NRC, in accordance with10 CFR 50.55a.ASME Code, Section XI inspection requirements for reactor vessel internals,(Subsection IWB, Categories B-N-1 and B-N-2) are not in the Inservice Inspection Program, but are included in the BWR Vessel Internals Program. For more information on the BWR Vessel Internals Program, see SER Section 3.0.3.2.7.The staff confirmed that the specific components for which the program manages agingeffects are identified by the applicant, which satisfied the criterion as defined in SRP-LR Appendix A.1.2.3.1. They conform to the scope of ISI as set forth in ASME Code, Section XI, Subsections IWA, IWB, IWC, IWD and IWF and approved by the staff in accordance with 10 CFR 50.55a. On this basis, the staff finds that the applicant's proposed program scope to be acceptable.The staff confirmed that the "scope of the program" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff finds this program element acceptable.  (2)Preventive Actions - LRA Section B.1.15.2 states that this program is a conditionmonitoring program that does not include preventive actions.The staff confirmed that the preventive actions program element satisfies the criteriadefined in SRP-LR Appendix A.1.2.3.2 for a condition monitoring program. On this basis, the staff finds the absence of preventive actions to be acceptable.The staff confirmed that the "preventive actions" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.2. The staff finds this program element acceptable.
3-124  (3)Parameters Monitored or Inspected - LRA Section B.1.15.2 states that this program usesNDE techniques to detect and characterize flaws. Volumetric examinations such as radiographic, ultrasonic or eddy current examinations are used to locate surface and subsurface flaws. Surface examinations, such as magnetic particle or dye penetrant testing, are used to locate surface flaws.The applicant also stated that three levels of visual examinations are specified. VT-1visual examination is conducted to assess the condition of the surface of the part being examined, looking for cracks and symptoms of wear, corrosion, erosion or physical damage. It can be done with either direct visual observation or with remote examination using various optical and video devices. VT-2 visual examination is conducted specificallyto locate evidence of leakage from pressure retaining components (period pressure tests). While the system is in accordance with pressure for a leakage test, visual examinations are conducted to detect direct or indirect indication of leakage. VT-3 visualexamination is conducted to determine general mechanical and structural condition of components and supports and to detect discontinuities and imperfections.The staff confirmed that the preventive actions program element satisfied the criteriadefined in SRP-LR Appendix A.1.2.3.3. They are consistent with the requirements of applicable subsections Section XI of the ASME Code. Although the 1998 Edition (with year 2000 Addenda) is in effect for the current (fourth) interval, the program addresses the need to increase or expand examination scope as required to satisfy the requirements of 10 CFR 50.55a. In addition, the program addresses the need to revisit the specific version of the ASME Code in subsequent intervals and to re-evaluate exemptions to be requested. On this basis, the staff finds that the applicant's description of the parameters monitored/inspected is acceptable.The staff confirmed that the "parameters monitored or inspected" program elementsatisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.3. The staff finds this program element acceptable.  (4)Detection of Aging Effects - LRA Section B.1.15.2 states that this program managescracking and loss of material, as applicable, for carbon steel, low alloy steel and stainless steel/nickel based alloy subcomponents of the RPV using NDE techniques specified inASME Code, Section XI, Subsection IWB examination categories.The applicant also stated that its Inservice Inspection Program manages cracking, loss ofpreload, loss of material, and reduction of fracture toughness, as applicable, of reactor coolant system components using NDE techniques specified in ASME Code, Section XI, Subsections IWB, IWC and IWD examination categories. No AERMs are identified for lubrite sliding supports. However, the Inservice Inspection Program will confirm the absence of aging effects for the period of extended operation.In addition, the applicant stated that its Inservice Inspection Program manages loss ofmaterial for ASME Code, Class 1, 2, and 3 steel piping supports and steel component supports within containment, using NDE techniques specified in ASME Code, Section XI, Subsection IWF examination categories.
3-125The staff confirmed that this program element satisfies the criteria defined in SRP-LRAppendix A.1.2.3.4 for the detection of aging effects. The applicant's Inservice Inspection Program has been reviewed and accepted by the staff in accordance with 10 CFR 50.55a. On this basis, the staff finds that the applicant's description of the detection of aging effects is acceptable.The staff confirmed that the "detection of aging effects" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.4. The staff finds this program element acceptable.  (5)Monitoring and Trending - LRA Section B.1.15.2 states that program results arecompared, as appropriate, to baseline data and, other previous test results. If indications are accepted for continued use by analytical evaluation, the areas containing such flawsare monitored during successive inspection periods.The applicant also stated that ISI results are recorded every operating cycle and providedto the NRC after each refueling outage via Owner's Activity Reports prepared by the Inservice Inspection Program Coordinator. These detailed reports include scope of inspection and significant inspection results.The staff confirmed that the monitoring and trending program element satisfied thecriteria defined in SRP-LR Appendix A.1.2.3.5. The implementing procedure and selected records of prior inspections were examined to confirm that the requirements of this program element are satisfied. On this basis, the staff finds that the applicant's description of the acceptance criteria is acceptable.The staff confirmed that the "monitoring and trending" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.5. The staff finds this program element acceptable.  (6)Acceptance Criteria - LRA Section B.1.15.2 states that in this program a preservice, orbaseline, inspection of program components was performed prior to startup to assure freedom from defects greater than code-allowable. This baseline data also provides a basis for evaluating subsequent inspection results. Since plant startup, additional inspection criteria for Class 2 and 3 components have been required by 10 CFR 50.55a, for which baseline data has also been obtained. Results are compared, as appropriate, to baseline data, other previous test results, and acceptance criteria of the ASME Boiler and Pressure Vessel Code, Section XI, 1998 Edition, 2000 Addenda, for evaluation of any evidence of degradation.The staff confirmed that the acceptance criteria program element satisfied the criteriadefined in SRP-LR Appendix A.1.2.3.6. The implementing procedure and selected records of prior inspections were examined to confirm that the requirements of this program element are satisfied. On this basis, the staff finds that the applicant's description of the acceptance criteria is acceptable.
3-126The staff confirmed that the "acceptance criteria" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.6. The staff finds this program element acceptable.
 
  (10)Operating Experience - LRA Section B.1.15.2 states that evaluation of pressureboundary components, including bolting, is by NDEs and visual inspections. Deviations from acceptance criteria are properly resolved. Inspections since 2001 revealed erosion of valve body internals, weld indications, recirculation pump bolting corrosion, and RHR valve bolting corrosion. The scope of welding inspections was expanded when rejectable indications were revealed. Condition reports documented indications and ensured resolution of those conditions. Corrective actions included repair and replacement of components. These actions prove that the program is effective at managing component aging effects. QA audits, QA surveillances, engineering system health reports, and staff inspections from 2001 to 2004 revealed no issues or findings that could impact program effectiveness.The staff reviewed the operating experience provided in the LRA, and interviewed theapplicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.
The staff confirmed that the "operating experience" program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.17, the applicant provided the UFSAR supplement forthe Inservice Inspection Program. The staff reviewed this section and finds the UFSAR supplement information an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its technical review of the applicant's Inservice Inspection Program,the staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-1273.0.3.3.4  Instrument Air Quality ProgramSummary of Technical Information in the Application. LRA Section B.1.16 describes theInstrument Air Quality Program as an existing, plant-specific program. The Instrument Air Quality Program maintains instrument air (IA) supplied to components free ofwater and significant contaminants, preserving an environment not conducive to loss of material.
Dewpoint, particulate contamination, and hydrocarbon concentration are checked periodically to maintain IA quality.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information inLRA Section B.1.16 on the applicant's demonstration of the Instrument Air Quality Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation.The staff reviewed the Instrument Air Quality Program against the AMP elements found in theGALL Report, in SRP-LR Appendix A.1.2.3, and in SRP-LR Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 elements (i.e., "scope of the program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance criteria," "corrective actions," "confirmation process," "administrative controls," and "operating experience").The applicant indicated that the "corrective actions," "confirmation process," and "administrativecontrols" program elements are parts of the site-controlled QA program. The staff's evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven elements follows:  (1)Scope of Program - LRA Section B.1.16 states that this program applies to componentswithin the scope of license renewal and subject to an AMR that are supplied with IA, for which pressure boundary integrity is required for the component to perform its intended function.The staff confirmed that the specific components for which the program manages agingeffects are identified by the applicant, which satisfied the criterion as defined in SRP-LR Appendix A.1.2.3.1. In addition, on the basis of a review of implementing procedures and discussions with the applicant's staff, the program reflects the VYNPS response to GL 88-14 as augmented by NRC Information Notice (IN) 81-38 and its first supplement.
On this basis, the staff finds that the applicant's proposed program scope is acceptable.The staff confirmed that the "scope of the program" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff finds this program element acceptable.  (2)Preventive Actions - LRA Section B.1.16 states that system air quality is monitored andmaintained within specified limits to ensure that IA supplied to components is maintained free of water and significant contaminants, thereby preventing loss of material.
3-128The staff confirmed that the preventive actions program element satisfies the criteriadefined in SRP-LR Appendix A.1.2.3.2. The activities for prevention and mitigation of aging effects on systems and components within the scope of license renewal that are supplied with IA are adequately described. On this basis, the staff finds that the applicant's preventive actions is acceptable.The staff confirmed that the "preventive actions" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.2. The staff finds this program element acceptable.  (3)Parameters Monitored or Inspected - LRA Section B.1.16 state that dewpoint, particulatecontamination and hydrocarbon concentration are periodically checked to verify IA quality is maintained.The staff confirmed that the preventive actions program element satisfied the criteriadefined in SRP-LR Appendix A.1.2.3.3. Dewpoint, particulate contamination and hydrocarbon concentration are linked to the aging effects of concern and are appropriate parameters to be monitored. Furthermore, in a letter dated July 6, 2006, the applicant committed to maintain the quality of compressed air in accordance with Instrument Society of America (ISA) S7.3 "Quality Standard for Instrument Air." On this basis, the staff finds that the applicant's description of the parameters monitored/inspected is acceptable.The staff confirmed that the "parameters monitored or inspected" program elementsatisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.3. The staff finds this program element acceptable.  (4)Detection of Aging Effects - LRA Section B.1.16 states that dewpoint, particulatecontamination and hydrocarbon concentration are periodically checked to verify IA quality is maintained, thereby preventing loss of material. At least once per 18 months, dew point, particulate contamination and hydrocarbon concentration are monitored at several locations in the IA system.The staff confirmed that the detection of aging effects program element satisfied thecriteria defined in SRP-LR Appendix A.1.2.3.4. The staff reviewed the implementing procedures for measuring dewpoint, particulate contamination and hydrocarbon concentration monitoring. Degradation of the piping and any components would become evident by observation of excessive corrosion or by failure of the system or any item of components to meet specified performance limits. On this basis, the staff finds that the applicant's description of the detection of aging effects is acceptable.The staff confirmed that the "detection of aging effects" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.4. The staff finds this program element acceptable.
3-129  (5)Monitoring and Trending - LRA Section B.1.16 states that results of sample analyses aremaintained in the chemistry log. A condition report is issued if data indicates deteriorating IA quality.The staff confirmed that for visual inspection, the monitoring and trending programelement satisfied the criteria defined in SRP-LR Appendix A.1.2.3.5. Effects of corrosion and the presence of contaminants are monitored by visual inspection and periodic system and component tests. On this basis, the staff finds that the applicant's description of monitoring and trending is acceptable.The staff confirmed that the "monitoring and trending" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.5. The staff finds this program element acceptable.  (6)Acceptance Criteria - LRA Section B.1.16 states that:
* dew point less than or equal to 40C
* maximum particle size is 3 micrometers
* hydrocarbon content less than or equal to 1 parts per million (ppm)The staff confirmed that the acceptance criteria program element satisfied the criteriadefined in SRP-LR Appendix A.1.2.3.6. The acceptance criteria specified in the VYNPS Instrument Air Quality Program have been found to be appropriate for managing the aging effects in the IA system. On this basis, the staff finds that the applicant's description of the acceptance criteria is acceptable.The staff confirmed that the "acceptance criteria" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.6. The staff finds this program element acceptable.
 
  (10)Operating Experience - LRA Section B.1.16 states that recent analyses revealed allparameters maintained within acceptance criteria. Absence of degradation of IA quality proves that the program is effective at maintaining IA supplied to components free of water and significant contaminants and preventing loss of material.The staff reviewed the operating experience provided in the LRA, and interviewed theapplicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable.
3-130UFSAR Supplement. In LRA Section A.2.1.18, the applicant provided the UFSAR supplement forthe Instrument Air Quality Program.The applicant committed (Commitment #28) to revise the program procedure by March 21,2012, to indicate that the Instrument Air Program maintains IA quality in accordance with ISA S7.3.The staff reviewed this section and determined that, upon the implementation of Commitment#28, the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its technical review of the applicant's Instrument Air Quality Programwith the addition of Commitment #28, the staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.3.5  Periodic Surveillance and Preventive Maintenance Program Summary of Technical Information in the Application. LRA Section B.1.22 describes the PeriodicSurveillance and Preventive Maintenance Program as an existing, plant-specific program. The Periodic Surveillance and Preventive Maintenance Program includes periodic inspectionsand tests that manage aging effects not managed by other AMPs. Preventive maintenance and surveillance testing are generally implemented through repetitive tasks or routine monitoring of plant operations. The program has taken credit in the AMR of the following systems and structures: reactor building, yard structures, HPCI system, standby gas treatment system (SGTS), primary containment atmosphere control (PCAC) system, SWS, EDG system, HVAC system, John Deere diesel, and nonsafety-related systems and components affecting safety-related systems.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information inLRA Section B.1.22 on the applicant's demonstration of the Periodic Surveillance and Preventive Maintenance Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation.The staff reviewed the Periodic Surveillance and Preventive Maintenance Program against theAMP elements found in the GALL Report, in SRP-LR Appendix A.1.2.3, and in SRP-LR Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 elements (i.e., "scope of the program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance criteria," "corrective actions," "confirmation process," "administrative controls," and "operating experience").
3-131The applicant indicated that the "corrective actions," "confirmation process," and "administrativecontrols" program elements are parts of the site-controlled QA program. The staff's evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven elements follows:  (1)Scope of Program - LRA Section B.1.22 states that this program, with regard to licenserenewal, includes those tasks credited with managing aging effects identified in AMRs.The staff confirmed that the specific components for which the program manages agingeffects are identified by the applicant, which satisfies the criterion as defined in SRP-LR Appendix A.1.2.3.1. On this basis, the staff finds that the applicant's proposed program scope acceptable.The staff confirmed that the "scope of the program" program element satisfies therecommendnation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff finds this program element acceptable.  (2)Preventive Actions - LRA Section B.1.22 states that inspection and testing activities usedto identify component aging effects do not prevent aging effects. However, activities are intended to prevent failures of components that might be caused by aging effects.The staff confirmed that the preventive actions program element satisfies the criteriadefined in SRP-LR Appendix A.1.2.3.2. Since inspection and testing activities do not rely on preventive actions and preventive actions need not be provided, the staff finds that the applicant's preventive actions acceptable.The staff confirmed that the "preventive actions" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.2. The staff finds this program element acceptable.  (3)Parameters Monitored or Inspected - LRA Section B.1.22 states that this programprovides instructions for monitoring structures, systems, and components to detect degradation. Inspection and testing activities monitor various parameters including system flow, system pressure, surface condition, loss of material, presence of corrosion products, and signs of cracking.The staff reviewed the applicant's basis document and compared with AMRs which creditPeriodic Surveillance and Preventive Maintenance Program and concurred with the applicant that inspection and testing activities monitor various parameters including system flow, system pressure, surface condition, loss of material, presence of corrosion products, and signs of cracking. The staff confirmed that the preventive actions program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.3. On this basis, the staff finds that the applicant's description of the parameters monitored or inspected is acceptable.The staff confirmed that the "parameters monitored or inspected" program elementsatisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.3. The staff finds this program element acceptable.
3-132  (4)Detection of Aging Effects - LRA Section B.1.22 states that preventive maintenanceactivities and periodic surveillances provide for periodic component inspections and testing to detect aging effects. Inspection intervals are established such that they provide timely detection of degradation. Inspection intervals are dependent on component material and environment and take into consideration industry and plant-specific operating experience and manufacturers' recommendations. Each inspection or test occurs at least once every ten years. The extent and schedule of inspections and testing assure detection of component degradation prior to loss of intended functions.
Established techniques such as visual inspections are used.The staff reviewed the applicant's basis document to confirm that the program providesinspection intervals and inspection method. The staff finds that periodic surveillance intervals and requirements meet TS requirements and the inspection and testing interval for surface condition degradation is 5 years. During the audit and review, the staff asked the applicant to justify if inspection intervalof 5 years for general corrosion of carbon steel CW system components exposed to raw water environment is adequate. The applicant responded that: (1) From reviewing its Service Water Monitoring Program, MIC is significantly inhibited when exposed to chlorination. Circulating water is periodically treated with chlorine, which further reduces this potential for attack for this system and that general corrosion, even in raw water systems such as circulating water, is not fast acting; (2) PSPM inspection activities are performed on 10 CFR 54.4(a)(2) systems that have been in service for the life of the plant without required inspections per the VYNPS corrective action program. If significant changes are noted, the frequency in the PSPM can be updated; (3) The consequences of failure due to loss of material are low; and (4) With the exception of the alternate cooling tower cell, the circulating water system does not run through the reactor building or near any safety-related equipment. Based on the aging stressors described above, the applicant concluded that the alternate cooling tower cell will not be impacted. In addition, SRP-LR Appendix A.1.2.2-3 states that risk significance may be considered in developing the details of an aging management program.The staff reviewed the information provided by the applicant. On the basis of its review ofthe applicant's technical justification and operating experience, the staff found that the inspection interval of 5 years is adequate for monitoring general corrosion of carbon steel components exposed to a raw water environment in the circulating water system to assure corrective action is taken prior to loss of intended function.The staff confirmed that this program element satisfies the criteria defined in SRP-LRAppendix A.1.2.3.4. The staff finds that the applicant's program provides inspection intervals and inspection method and that periodic surveillance interval and requirements meet TS requirement and the inspection and testing interval for surface condition degradation is 5 years. On this basis, the staff finds that the applicant's description of the detection of aging effects is acceptable.The staff confirmed that the "detection of aging effects" program element satisfiestherecommendnation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.4. The staff finds this program element acceptable.
3-133  (5)Monitoring and Trending - LRA Section B.1.22 states that preventive maintenance andsurveillance testing activities provide for monitoring and trending of aging degradation.
Inspection and testing intervals are established such that they provide for timely detection of component degradation. Inspection and testing intervals are dependent on component material and environment and take into consideration industry and plant-specific operating experience and manufacturers' recommendations.The staff reviewed applicant's program and its related operating procedures anddetermines the program is used to identify component degradation. Any degraded components will be handled through CAP. The staff determines that for visual inspection, this program element satisfies the criteria defined in Appendix SRP-LR A.1.2.3.5. On this basis, the staff finds that the applicant's description of the monitoring and trending is acceptable.The staff confirmed that the "monitoring and trending" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.5. The staff finds this program element acceptable.  (6)Acceptance Criteria - LRA Section B.1.22 states that this program's acceptance criteriaare defined in specific inspection and testing procedures. The procedures confirm component integrity by verifying the absence of aging effects or by comparing applicable parameters to limits based on applicable intended functions established by plant design
 
basis.The staff reviewed VYNPS operating procedures for various systems (primarycontainment surveillance, secondary containment surveillance) and confirmed that the testing frequency is determined by the IST program criteria and the TS and is performed as scheduled by the surveillance test schedule.The staff also reviewed the VYNPS operating procedures and confirmed that theapplicant's acceptance criteria were clearly defined in its operating procedures. For example, the staff reviewed applicant's procedures, as documented in the Audit and Review Report, and confirmed the acceptance criteria established by plant design basis.
On the basis of its review, the staff determines that acceptance criteria of the applicant's program satisfied the criteria defined in SRP-LR Appendix A.1.2.3.6. On this basis, the staff finds this acceptable.The staff confirmed that the "acceptance criteria" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.6. The staff finds this program element acceptable.
 
  (10)Operating Experience - LRA Section B.1.22 states that recent inspection results (2001 to2004) show that the program is effective in managing component aging effects. For example, the material condition of cranes was consistent with inspection acceptance criteria to which the program documents referred (i.e., no significant corrosion or wear; equipment lock sliding doors had no significant wear or corrosion; HPCI turbine GSC tubes were not fouled; HPCI turbine casing had no significant corrosion or erosion; standby gas treatment demister and loop seal components had no significant corrosion; 3-134John Deere diesel exhaust gas components had no significant corrosion or cracking; andECCS corner room recirculation units had no significant corrosion). QA audits andsurveillances, self-assessments, engineering system health reports, and staff inspections from 2001 to 2004 concluded that actions to preclude recurrence of a previous adverse trend had been effective and revealed no issues or findings that could impact program effectiveness.The staff reviewed the operating experience provided in the LRA, and interviewed theapplicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.24, the applicant provided the UFSAR supplement forthe Periodic Surveillance and Preventive Maintenance Program.The applicant committed ( Commitment #17) to enhance the Periodic Surveillance and PreventiveMaintenance Program to assure that the effects of aging will be managed by March 21, 2012. The staff reviewed this section and determined that, upon the implementation of Commitment#17, the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its technical review of the applicant's Periodic Surveillance andPreventive Maintenance Program with the addition of Commitment #17, the staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-1353.0.3.3.6  Vernon Dam FERC InspectionSummary of Technical Information in the Application. LRA Section B.1.27.3 and LRA supplementdated July 3, 2007 describe the Vernon Dam FERC Inspection as an existing, plant-specific program. The Vernon Dam is subject to the Federal Energy Regulatory Commission (FERC) inspectionprogram. This program consists of visual inspections in accordance with FERC guidelines andcomplies with Tittle 18 of the Code of Federal Regulations (CFR), Conservation of Power andWater Resources, Part 12, (Safety of Water Power Projects and Project Works), and Division of Dam Safety and Inspections Operating Manual. In accordance with FERC regulations, the owner has been granted an exemption from part 12, Subpart D. As indicated in NUREG-1801 for water control structures, NRC has found that FERC / US Army Corp of Engineers dam inspections and maintenance program are acceptable for aging management. In addition, Vernon dam personnel conduct a daily visual inspection of all the project facilities. An operations crew attends the plantdaily. Vernon dam engineering performs an annual inspection of all the project structures and divers make a thorough inspection once every five year on both upsteam and downsteam sides.
The operational inspection frequency for licensed and exempt low hazard potential dams is biennial. Reports of operational inspections are filed with the FERC.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information inLRA Section B.1.27.3 and the July 3, 2007 supplement on the applicant's demonstration of the Vernon Dam FERC Inspection to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation.The applicant stated that the Vernon Dam FERC Inspection Program is an existing plant-specificprogram. Vernon Dam is subject to the FERC inspection program. This program consists of a daily visual inspection of all the project facilities by Vernon Dam personnel. An operations crew attends the plant daily. Vernon dam engineering performs an annual inspection of all the project structures and divers make a thorough inspection once every five year on both upstream and downstream sides, and is in compliance with Title 18 of the Code of Federal Regulations, Conservation of Power and Water Resources, Part 12 (Safety of Water Power Projects and Project Works). The NRC has found that mandated FERC inspection programs are acceptable for aging management.The applicant stated, in the LRA, in accordance with the operating experience, that recentinspections (1998-2002) of the Vernon Dam found minor concrete erosion on the spillway, a crack on a downstream pier, concrete surface erosion in the stanchion flashboard section, spalling at the base of a trash sluice wall, and a crack in the spillway gallery. None of these conditions are threatening structural support and, therefore, do not require immediate repair.
However, the areas of degradation will continue to be monitored. Continued monitoring of minor degradation provides evidence that the program is effective for managing aging effects for the dam.Recent FERC assessment (2002) of the Vernon Dam structures found that SCs are maintained inaccordance with terms of the license, including daily visual inspections of structural integrity, and periodic underwater inspections on both the upstream and downstream sides of the dam.
3-136In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in LRASection B.1.27.3, regarding the applicant's demonstration of the Vernon Dam FERC Inspection to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation.The staff reviewed the program basis documents and reports. In addition, the staff reviewed thelisted operating experience in which FERC inspections of Vernon Dam found minor concrete erosion on the spillway, a crack on a downstream pier, concrete surface erosion in the stanchion flashboard section, spalling at the base of a trash sluice wall, and a crack in the spillway gallery and found that the FERC inspections were effective in identifying aging effects on Vernon Dam.
The above deficiencies were noted for continued monitoring by the Vernon Dam owner and during the continuing FERC Dam inspections. None of these conditions are threatening structural support and, therefore, do not require immediate repair. However, the areas of degradation will continue to be monitored.The staff reviewed the operating experience provided in the LRA, and interviewed the applicant'stechnical personnel and the dam's owner to confirm that the operating experience did not reveal any degradation not bounded by industry experience.During the audit and review, the staff found FERC letter dated August 6, 1997, which exemptedthe Vernon Hydroelectric Station (VHS) from the requirement of 18 CFR Part 12, Subpart D for submittal of an Independent Consultant's Safety Inspections Report, based on its low hazard classification. The staff's interpretation of the August 6, 1997, letter led it to assume that the dam owner still had to perform the Subpart D inspection but did not have to submit the report for FERC review and approval. For clarification, the FERC New York Regional Office was contacted.
In its response to the staff on November 2, 2006, FERC stated: The intention of the letter issued on August 6, 1997... was to exempt the VernonProject from all the requirements of Part 12, Subpart D of 18 CFR. This includes not only the requirement to submit a report but also the requirement of having the dam inspected by an Independent Consultant.The staff also reviewed the applicant responses to RAI 3.6.2.2-N-08. In its letter date July 14,2006, the applicant stated:Entergy, consistent with the Peach Bottom precedent, credited the [Federal EnergyRegulatory Commission] FERC dam inspection program to manage the effects of aging on civil and structural elements of the VHS.Since the daily and annual inspections of the dam are not part of a VYNPS aging managementprogram but are conducted by the dam owner under FERC oversight, the applicant was asked in RAI 3.6.2.2-N-08-1 to describe specific reports, and describe any corrective actions that have been taken as a result of the inspection reports as they pertain to the VHS as required by 10 CFR 54.21(a)(3). In letter dated July 3, 2007, the applicant committed (Commitment #50) that during the period ofextended operation, at least once every five years, VYNPS will confirm that the Vernon Dam 3-137owner is performing the required FERC inspections based on a review of the Vernon Damowner's reports to FERC. VY will document the condition in the Entergy Correction Actions Program and evaluate operability as described in BVY 96-043 and BVY 97-025 if it is determined that the required inspections are not being performed.
Conclusion. The staff finds that the aging management for the Vernon Dam is performed by theowner of the VHS and FERC. In addition, inspections with reports are performed by the FERC New York Regional office. On the basis of its review of the operating experience and discussions with the applicant's technical personnel, the dam's owner, and the FERC New York Regional Office, the staff concludes that the FERC inspection program in addition to the daily visual inspections and the annual inspection conducted by Vernon Dam personnel will adequately manage the aging effects for the Vernon Dam. 3.0.3.3.7  Water Chemistry Control - Auxiliary Systems Program Summary of Technical Information in the Application. LRA Section B.1.30.1 describes the WaterChemistry Control - Auxiliary Systems Program as an existing, plant-specific program. The purpose of the Water Chemistry Control - Auxiliary Systems Program is to manage agingeffects for components exposed to treated water. Program activities include sampling and analysis of stator cooling water and plant heating boiler systems and flushing of the John Deere diesel cooling water system.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information inLRA Section B.1.30.1 on the applicant's demonstration of the Water Chemistry Control - Auxiliary Systems Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation.The staff reviewed the Water Chemistry Control - Auxiliary Systems Program against theAMP elements found in the GALL Report, in SRP-LR Appendix A.1.2.3, and in SRP-LR Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 elements (i.e., "scope of the program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance criteria," "corrective actions," "confirmation process," "administrative controls," and "operating experience").The applicant indicated that the "corrective actions," "confirmation process," and "administrativecontrols" program elements are parts of the site-controlled QA program. The staff's evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven elements follows:  (1)Scope of Program - LRA Section B.1.30.1 states that program activities include samplingand analysis of stator cooling water and plant heating boiler systems, and flushing of the John Deere Diesel cooling water system.
3-138The staff confirmed that the specific components for which the program manages agingeffects are identified by the applicant, which satisfies the criterion as defined in SRP-LR Appendix A.1.2.3.1. On this basis, the staff finds that the applicant's proposed program scope acceptable.The staff confirmed that the "scope of the program" program element satisfies therecommendnation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff finds this program element acceptable.  (2)Preventive Actions - LRA Section B.1.30.1 states that this program includes monitoringand control of stator cooling water and plant heating boiler FW to minimize exposure to aggressive environments and application of corrosion inhibitors to manage general, crevice, and pitting corrosion. John Deere Diesel cooling water chemistry is controlled to minimize exposure to aggressive environments by periodic flushing and replacement of the coolant and coolant conditioner.The staff reviewed the applicant's basis document, which stated that Cortrol OS 7700 and50 percent Sodium Hydroxide were added as a corrosion inhibitor. Cortrol OS 7700 is added to boiler FW and contains an oxygen scavenger (hydroquinone) to reduce generalized corrosion, and a neutralized amine to minimize localized or pitting corrosion. The staff confirmed that the existing chemistry activities and preventive actions taken bythe applicant satisfies the criteria in SRP-LR Appendix A.1.2.3.2. The staff reviewed the applicant's basis document, as documented in the Audit and Review Report, which stated that Cortrol OS 7700 and 50 percent Sodium Hydroxide were added as a corrosion inhibitor. Cortrol OS 7700 is added to boiler FW and contains an oxygen scavenger (hydroquinone) to reduce generalized corrosion, and a neutralized amine to minimize localized or pitting corrosion. On this basis, the staff finds that the applicant's preventive actions acceptable.The staff confirmed that the "preventive actions" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.2. The staff finds this program element acceptable.  (3)Parameters Monitored or Inspected - LRA Section B.1.30.1 states that in accordance withindustry recommendations, stator cooling water and plant heating boiler FW parameters monitored include conductivity, corrosion products, and dissolved oxygen. The applicant also stated that the procedure will be enhanced (Commitment #26) to flush the John Deere Diesel generator cooling water system and replace the coolant and coolant conditioner every three (3) years. The staff confirmed that the preventive actions program element satisfies the criteriadefined in SRP-LR Appendix A.1.2.3.3. The staff reviewed the applicant's basis documents, as documented in the Audit and Review Report, to determine that applicant's monitoring schedule is adequate. The staff concludes that the dissolved oxygen, metals and conductivity are monitored per the surveillance schedule. On this basis, the staff finds that the applicant's description of the parameters monitored or inspected is acceptable.
3-139The staff confirmed that the "parameters monitored or inspected" program elementsatisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.3. The staff finds this program element acceptable.  (4)Detection of Aging Effects - LRA Section B.1.30.1 states that this program manages lossof material for stator cooling water, plant heating boiler, and John Deere Diesel system components.The applicant also stated in LRA Section B.1.30.1, that the One-Time Inspection Programdescribes inspections planned to verify the effectiveness of water chemistry control programs to ensure that significant degradation is not occurring and component intended function is maintained during the period of extended operation.The staff confirmed that the detection of aging effects program element satisfies thecriteria defined in SRP-LR Appendix A.1.2.3.3. The staff acknowledged that this is a mitigation program and does not provide for detection of any aging effects, such as loss of material and crack initiation and growth. The applicant's One-time inspection program is to be undertaken to verify the effectiveness of the water chemistry program to ensure that significant degradation is not occurring. On this basis, the staff finds that the applicant's description of the detection of aging effects is acceptable.The staff confirmed that the "detection of aging effects" program element satisfies therecommenndation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.4. The staff finds this program element acceptable.  (5)Monitoring and Trending - LRA Section B.1.30.1 states that program values from analysesare archived for long-term trending and review.The staff confirmed that this program element satisfies the criteria defined in SRPSection A.1.2.3.5. The staff reviewed procedure, as documented in the Audit and Review Report, to determine that applicant's monitoring schedule is adequate. On the basis of its review, the staff concludes that the dissolved oxygen, metals and conductivity are monitored per the surveillance schedule. The staff determines the program was used to monitor chemistry content and any abnormal chemistry reported will be handled through CAP. On this basis, the staff finds the applicant's monitoring and trending acceptable.The staff confirmed that the "monitoring and trending" program element satisfies therecommenndation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.5. The staff finds this program element acceptable.  (6)Acceptance Criteria - LRA Section B.1.30.1 states that acceptance criteria for chemistryparameters are in accordance with specific manufacturer's recommendations and general guidelines provided in EPRI Report 1007820, "Revision 1 to TR-107396, Closed Cooling Water Chemistry Guidelines."The staff reviewed the acceptance criteria in the applicant's program basis documents.The staff determines that the acceptance criteria for chemistry parameters are in accordance with specific manufacture's recommendations and general guidelines 3-140provided in EPRI Report 1007820, "Revision 1 to TR-107396, Closed Cooling WaterChemistry Guidelines." On this basis, the staff finds the applicant's acceptance criteria isacceptable.The staff confirmed that this program element satisfies the criteria defined in SRP-LRAppendix A.1.2.3.6. The staff reviewed the acceptance criteria in the applicant's program basis documents, as documented in the Audit and Review Report. The staff determines that the acceptance criteria for chemistry parameters are in accordance with specific manufacture's recommendations general guidelines provided in EPRI Report 1007820, "Revision 1 to TR-107396, Closed Cooling Water Chemistry Guidelines." On this basis, the staff finds the applicant's acceptance criteria acceptable.The staff confirmed that the "acceptance criteria" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.6. The staff finds this program element acceptable.  (10)Operating Experience - LRA Section B.1.30.1 states that stator cooling water and househeating boiler sample results in 2004 and 2005 show parameters within acceptance criteria, proving that the program is effective for managing component loss of material, cracking, and fouling. A QA audit in 2003 revealed no issues or findings that could impact program effectiveness.The staff reviewed the operating experience provided in the LRA, and interviewed theapplicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed.The staff confirmed that the "operating experience" program element satisfies therecommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable.UFSAR Supplement. In LRA Section A.2.1.34, the applicant provided the UFSAR supplement forthe Water Chemistry Control - Auxiliary Systems Program.In addition, in a letter dated January 14, 2007, the applicant provided an amendment to its LRA toexplicitly state, "One-Time Inspection Program," activities will confirm the effectiveness of "Water Chemistry Control - Auxiliary Systems Program."The applicant committed (Commitment #26) to enhance procedures to flush the John DeereDiesel Generator cooling water system and replace the coolant conditioner every three years by March 21, 2012.The staff reviewed LRA Section A.2.1.34 and determined that, upon the implementation ofCommitments #26, the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-141 Conclusion. On the basis of its technical review of the applicant's Water Chemistry Control -Auxiliary Systems Program with the addition of Commitment #26, the staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.3.8  Bolted Cable Connections Program Summary of Technical Information in the Application. In a letter dated January 4, 2007, applicantrevised its LRA. The applicant submitted its Appendix B, Section B.1.33, "Bolted Cable Connections Program." The applicant described that the Bolted Cable Connections Program is a plant-specific program. Cable connections are used to connect cable conductors to the cables orelectrical devices. Connections associated with cables within the scope of license renewal areconsidered in this program. The most common types of connections used in the nuclear power plants are splices (butt or bolted), crimp-type ring lugs, connectors, and terminal blocks. Most connections involve insulting material and metallic parts. This AMP for electrical cableconnections (metallic parts) accounts for loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation.This program has been developed as an alternate to GALL AMP XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirement." The applicant also stated that this program will be implemented prior to the period of extended operation. Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the informationincluded in revised LRA Section B.1.33, regarding the applicant's demonstration of the Bolted Cable Connections Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The Audit and Review Report details the staff's audit evaluation of this AMP.The staff reviewed the Bolted Cable Connections Program against the AMP elements finds in theGALL Report, SRP-LR Appendix A.1.2.3 and SRP-LR Table A.1-1, focusing its review on how the program manages aging effects through the effective incorporation of 10 elements (i.e., "scope of program," "preventive actions," "parameters monitored/inspected," "detection of aging effects,"
"monitoring and trending," "acceptance criteria," "corrective actions," "confirmation process,"
"administrative controls," and "operating experience"). The staff's evaluation of the 10 program element are provided below. The staff's evaluation of the applicant's QA program is discussed in SER Section 3.0.4.  (1)Scope of Program - The applicant stated, in revised LRA, that this program applies toNon-Environmental qualification connections associated with cables in-scope of license renewal. This program does not include the high-voltage (>35 kV) switchyard connections.
In-scope connections are evaluated for applicability of this program. The criteria for including connections in the program are that the connection is a bolted connection and is not covered in accordance with the Environmental Qualification Program or an existing preventive maintenance program.
3-142The staff determines that the specific commodity groups for which the program managesaging effects are identified (Non-environmental qualification bolted cable connections associated with cables in-scope of license renewal), which satisfies the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff determines that the exclusion of high-voltage (>35 kV) switchyard connections, connections covered in accordance with the Environmental Qualification Program, and an existing preventive maintenance program, acceptable.
Switchyard connections are addressed in SER Section 3.6.2.2. Environmental qualification cable connections are covered as required by 10 CFR 50.49. Cable connections in accordance with a preventive maintenance program are periodically inspected. On this basis, the staff finds that the applicant's scope of program acceptable.  (2)Preventive Actions - The applicant stated, in the revised LRA, that this one-time inspectionprogram is a condition monitoring program; therefore, no actions are taken as part of this program to prevent or mitigate aging degradation.The staff determines that the preventive actions program element satisfies the criteriadefined in SRP-LR Appendix B.1.2.3.2. The staff finds it acceptable because this is a condition monitoring program and there is no need for preventive actions. On this basis, the staff finds the applicant's preventive actions acceptable.    (3)Parameters Monitored/Inspected - The applicant stated, in the revised LRA, that thisprogram will focus on the metallic parts of the cable connections. The one-time inspection verifies that the loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation is not anissue that requires a periodic AMP.The staff determines that the parameters monitored/inspected program element satisfiesthe criteria defined in SRP-LR Appendix A.1.2.3.3. Loosening (or high resistance) of bolted cable connections are the potential aging effects due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation.The design of bolted cable connections usually account for the above stressors. The one-time inspection is to confirm that these stressors are not an issue that requires a periodic AMP. On this basis, the staff finds that the applicant's parameters monitored or inspected acceptable.    (4)Detection of Aging Effects - The applicant stated, in the revised LRA, that a representativesample of electrical connections within the scope of license renewal, are subject to an AMR and will be inspected or tested prior to the period of extended operation to verify there are no AERMs during the period of extended operation. The factors considered for sample selection will be application (medium and low voltage), circuit loading (high load),
and location (high temperature, high humidity, vibration, etc.). The technical basis for the sample selected is to be documented. Inspection methods may include thermography, contact resistance testing, or other appropriate methods including visual, based on plant configuration and industry guidance. The one-time inspection provides additional confirmation to support operating experience that shows electrical connections have not experienced a high degree of failures, and that existing installation and maintenance practices are effective.
3-143The staff determines that this program element satisfies the criteria defined in SRP-LRAppendix A.1.2.3.4. Thermography is used to detect aging effects of bolted cable connections due to thermal cycling, ohmic heating, electrical transients, and vibration.
Contact resistance measurement is an appropriate inspection technique to detect high resistance of bolted cable connections due to chemical contamination, corrosion, andoxidation. Visual inspection is an alternative technique to thermography or measuring connection resistance of bolted connections that are covered with materials like heat shrink tape, sleeving, and insulating boots. The staff also determines that the proposed one-time inspection is acceptable because the design of these connections will accountfor the stresses associated with the above aging effects and one-time inspection is to confirm that these stressors/mechanisms should not be a significant aging issue. On this basis, the staff finds that the applicant's detection of aging effects acceptable.  (5)Monitoring and Trending - The applicant stated, in the revised LRA, that in this program,trending actions are not included as part of this program because this is a one-time inspection.The staff determines that absence of trending for testing is acceptable, since the test is aone-time inspection and the ability to trend inspection results is limited by the available data. Furthermore, the staff did not see a need for such activities. On this basis, the staff finds the applicant's monitoring and trending acceptable.  (6)Acceptance Criteria - The applicant stated, in the revised LRA, that the acceptance criteriafor each inspection/surveillance are defined by the specific type of inspection or test performed for the specific type of cable connections. Acceptance criteria ensure that the intended functions of the cable connections can be maintained consistent with the CLB.The staff determines that this program element satisfies the criteria defined in SRP-LRAppendix A.1.2.3.6. The staff finds it acceptable on the basis that acceptance criteria for inspection/surveillance are defined by the specific type of inspection or test performed for the specific type of connection. The applicant will follow current industry standards which, when implemented, will ensure that the license renewal intended functions of the cable connections will be maintained consistent with the CLB.    (7)Corrective Actions - The adequacy of the applicant's 10 CFR 50, Appendix B Programassociated with this program element was reviewed by the staff and is addressed in SER Section 3.0.4.The staff reviewed other aspects of this program element to determine whether or not itsatisfies the criteria defined in SRP-LR Appendix A.1.2.3.7. In the LRA, the applicant stated that corrective actions are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. The staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address corrective actions. On this basis, the staff finds that the applicant's description of the corrective actions is acceptable.  (8)Confirmation Process - The adequacy of the applicant's 10 CFR 50, Appendix B Programassociated with this program element was reviewed by the staff and is addressed in SER Section 3.0.4.
3-144The staff reviewed other aspects of this program element to determine whether or not itsatisfies the criteria defined in SRP-LR Appendix A.1.2.3.8. In the LRA, the applicant stated that the confirmation process is part of the CAP. The CAP constitutes the confirmation process for AMPs and activities. On this basis, the staff finds that the applicant's description of the confirmation process is acceptable.  (9)Administrative Controls - The adequacy of the applicant's 10 CFR 50, Appendix BProgram associated with this program element was reviewed by the staff and is addressed in SER Section 3.0.4.The staff reviewed other aspects of this program element to determine whether or not itsatisfies the criteria defined in SRP-LR Appendix A.1.2.3.9. In the LRA, the applicant stated that the administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. The staff finds the requirements of 10 CFR Part 50, Appendix B acceptable to address administrative controls. On this basis, the staff finds that the applicant's description of the administrative controls is acceptable.  (10)Operating Experience - The applicant stated, in the revised LRA, that operatingexperience has shown that loosening of connections and corrosion of connections could be a problem without proper installation and maintenance activities. Industry operating experience supports performing this one-time inspection program in lieu of a periodic testing program. This one-time inspection program will verify that the installation and maintenance activities are effective. To address NEI's concerns about the lack of operating experience to support GALL AMP XI.E6(NEI's White Paper on GALL AMP XI.E6, dated September 5, 2006), the staff confirmed that there is little operating experience related to failed connections due to aging that have been identified and these operating experience do not support a periodic inspection as currently recommended in GALL AMP XI.E6. The staff finds that the proposed one-time inspection program will ensure that either aging of metallic cable connections is not occurring or existing preventive maintenance program is effective such that a periodic inspection program is not required. On the basis of its review, the staff concludes that the applicant's Bolted Cable ConnectionsProgram will verify that aging of metallic cable connections is not occurring and the installation and maintenance activities are effective.UFSAR Supplement. In revised LRA Section A.2.1.39, the applicant provided the UFSARsupplement for the Bolted Cable Connections Program. The applicant stated that its Bolted Cable Connections Program will focus on the metallic parts of the cable connections. This sampling program provides a one-time inspection to verify that the loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion,and oxidation is not an aging issue that requires a periodic AMP. A representative sample of the electrical cable connection population subject to an AMR will be inspected or tested. Connectionscovered in accordance with the Environmental Qualification program, or connections inspected or tested as part of a preventive maintenance program are excluded from an AMR. The factors considered for sample selection will be application (medium and low voltage), circuit loading (high 3-145load), and location (high temperature, high humidity, vibration, etc.) The technical basis for thesample selected is to be documented. This program will be implemented prior to the period of extended operation. The staff reviewed the UFSAR supplement, and determines that it provides a adequate summarydescription of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its review of the applicant's program, the staff finds that the applicanthas demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained during the period of extended operation, as required by 10 CFR 54.21(a)(3). On the basis of its review of the UFSAR supplement for this program, the staff also finds that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.4  Quality Assurance Program Attributes Integral to Aging Management ProgramsPursuant to 10 CFR 54.21(a)(3), the applicant is required to demonstrate that the effects of agingon SCs subject to an AMR will be adequately managed so that their intended function(s) will be maintained consistent with the CLB for the period of extended operation. SRP-LR, Branch Technical Position (BTP) RLSB-1, "Aging Management Review-Generic," describes ten elements of an acceptable AMP. Elements (7), (8), and (9) are associated with the QA activities of "corrective actions," "confirmation process," and "administrative controls." BTP RLSB-1 Table A.1-1, "Elements of an Aging Management Program for License Renewal," provides the following description of these program elements:(7)Corrective Actions - Corrective actions, including root causedetermination and prevention of recurrence, should be timely.(8)Confirmation Process - The confirmation process should ensurethat preventive actions are adequate and that appropriate corrective actions have been completed and are effective.(9)Administrative Controls - Administrative controls should provide aformal review and approval process.Those aspects of the AMP that affect the quality of safety-related SSCs and are subject to theQA requirements of 10 CFR Part 50, Appendix B are noted in SRP-LR, BTP IQMB-1, "Quality Assurance for Aging Management Programs." Additionally, for nonsafety-related SCs subject to an AMR, the existing 10 CFR Part 50 Appendix B QA program may be used by the applicant to address the elements of corrective action, confirmation process, and administrative control.
BTP IQMB-1 provides the following guidance with regard to the QA attributes of AMPs:Safety-related SCs are subject to 10 CFR Part 50 Appendix Brequirements which are adequate to address all quality-related aspects of an AMP consistent with the CLB of the facility for the period of extended operation.
3-146For nonsafety-related SCs that are subject to an AMR, an applicanthas an option to expand the scope of its 10 CFR Part 50 Appendix B program to include these SCs to address corrective action, confirmation process, and administrative control for aging management during the period of extended operation. In this case, the applicant should document such commitment in the UFSAR supplement in accordance with 10 CFR 54.21(d).3.0.4.1  Summary of Technical Information in the ApplicationIn LRA Sections A.2.1, "Aging Management Programs and Activities," and B.0.3, "VYNPSCorrective Actions, Confirmation Process and Administrative Controls," the applicant described the elements of corrective action, confirmation process, and administrative controls that are applied to the AMPs for both safety-related and nonsafety-related components. A single QA Program is used which includes the elements of corrective action, confirmation process, and administrative controls. Corrective actions, confirmation, and administrative controls are appliedin accordance with the CAP regardless of the safety classification of the components.
Specifically, in LRA Sections A.2.1 and B.0.3, respectively, the applicant stated that the QA Program implements the requirements of 10 CFR 50, Appendix B, and is consistent with NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants."LRA Section 3.0, "Aging Management Review Results," provided an AMR summary for eachunique component type or commodity group determined to require aging management during the period of extended operation. 3.0.4.2  Staff EvaluationPursuant to 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects of agingon SCs subject to an AMR will be adequately managed so that their intended functions will be maintained consistent with the CLB for the period of extended operation. NUREG-1800, BTP RLSB-1, "Aging Management Review - Generic," describes ten attributes of an acceptable AMP. Three of these ten attributes are associated with the QA activities of corrective action, confirmation process, and administrative control. BTP RLSB-1, Table A.1-1, "Elements of an Aging Management Program for License Renewal," provides the following description of these quality attributes:corrective actions, including root cause determination and prevention of recurrence,should be timely;the confirmation process should ensure that preventive actions are adequate and thatappropriate corrective actions have been completed and are effective; and,administrative controls should provide a formal review and approval process.NUREG-1800, BTP IQMB-1 noted that those aspects of the AMP that affect quality ofsafety-related SSCs are subject to the QA requirements of Appendix B to 10 CFR Part 50.
Additionally, for nonsafety-related SCs subject to an AMR, the applicant's existing Appendix B to 3-14710 CFR Part 50 QA program may be used to address the elements of corrective action,confirmation process, and administrative control. BTP IQMB-1 provides the following guidance with regard to the QA attributes of AMPs:Safety-related SCs are subject to Appendix B to 10 CFR Part 50 requirements which areadequate to address all quality-related aspects of an AMP consistent with the CLB of the facility for the period of extended operation. For nonsafety-related SCs that are subject to an AMR for license renewal, an applicant has an option to expand the scope of its Appendix B to 10 CFR Part 50 program to include these SCs to address corrective action, confirmation process, and administrative control for aging management during the period of extended operation. In this case, the applicant should document such a commitment in the Final Safety Analysis Report (FSAR) supplement in accordance with 10 CFR 54.21(d).The staff reviewed the applicant's AMPs described in LRA Appendix A, Section A.2.1,Appendix B, Sections B.0.3 and B.1, and in applicant's AMP evaluation reports. The purpose of this review was to ensure consistency in the use of the QA attributes for each program and that aging management activities were consistent with the staff's guidance described in NUREG-1800, BTP IQMB-1.During the review of the LRA and AMP evaluation reports, the staff identified inconsistenciesassociated with corrective action, confirmation, and administrative control processes regarding the AMP for the VHS structural components. LRA Section B.1.27 and the AMP evaluation reports stated that the AMP was consistent with NUREG-1801 and that the applicants CAP was applicable to the VHS. When discussing this AMP with the applicant, the applicant stated that it did not own the VHS and that its CAP did not apply to VHS as indicated in the LRA and AMP evaluation reports. Additionally, the staff found that AMP evaluation reports did not consistently describe the application of the 10 CFR Part 50, Appendix B, QA Program for the corrective action, confirmation process, and administrative control attributes for each AMP. In RAI 3.0-1, dated July 10, 2006, the staff requested that the applicant clarify its use of the10 CFR Part 50, Appendix B, QA Program for corrective action, confirmation process, and administrative controls, and to supplement the LRA, as necessary, to clearly indicate the application of the QA Program, or an alternative for the corrective action, confirmation, and administrative control process attributes for each AMP. In its responses, by letters dated July 14, 2006, August 10, 2006, October 20, 2006, andJanuary 4, 2007, the applicant further described the application of the VYNPS 10 CFR Part 50, Appendix B, QA Program for corrective action, confirmation process, and administrative controls, and provided a revision to the UFSAR Supplement. The revision stated, in part:The corrective action, confirmation process, and administrative controls of theENTERGY (10 CFR Part 50, Appendix B) Quality Assurance Program are applicable to all aging management programs that will be required during the period of extended operation, with the exception of the Vernon Dam FERC inspection.
3-148With respect to the VHS, the applicant stated, in part, that although the VHS is not under theVYNPS QA program, any issues identified with respect to the availability of the VHS to perform its license renewal intended function will require invoking the VYNPS QA program. The VHS civil and structural elements will be managed through the continued use of the FERC dam inspection program, and the pertinent electrical system elements will be managed through a combination of VYNPS AMPs and the inspection and periodic maintenance processes of the owner/operator. In the event that any of these processes identify a condition which indicates the VHS is incapable of performing its license renewal intended function, this will require entry into the VYNPS corrective action program (in accordance with the VYNPS Technical Specifications) and therefore invokes the associated elements of the VYNPS QA program. Additionally, the applicant monitors the availability of the VHS to ensure continued ability to perform its License renewal intended function, through conformance with the availability specified in the NUMARC 87-00 for meeting the requirements of the SBO rule, and will invoke the VYNPS Corrective Action program if those requirements cannot be maintained.The staff has reviewed the applicant's responses to this RAI and concluded that the applicant has adequately addressed the staff's concerns associated with implementation of the VYNPS 10 CFR Appendix B Quality Assurance Program with respect to the VYNPS AMPs and the VHS.
Therefore, the staff's concern described in RAI 3.0-1 is resolved. 3.0.4.3  ConclusionOn the basis of the staff's evaluation, the descriptions and applicability of the plant-specific AMPsand their associated quality attributes provided in LRA Appendix A, Section A.2.1, and Appendix B, Sections B.0.3 and B.1, and the RAI response, are consistent with the staff's position regarding QA for aging management. The staff concludes that the QA attributes (corrective action, confirmation process, and administrative control) of the applicant's AMPs are consistent with the requirements of 10 CFR 54.21(a)(3). 3.1  Aging Management of Reactor Vessel, Reactor Vessel Internals, and ReactorCoolant SystemThis section of the SER documents the staff's review of the applicant's AMR results for the reactor vessel, reactor vessel internals, and reactor coolant system components and component groups of:
* reactor vessel
* reactor vessel internals
* reactor coolant pressure boundary3.1.1  Summary of Technical Information in the ApplicationLRA Section 3.1 provides AMR results for the reactor vessel, reactor vessel internals, and reactorcoolant system components and component groups. LRA Table 3.1.1, "Summary of Aging Management Evaluations for the Reactor Coolant System," is a summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the reactor vessel, reactor vessel internals, and reactor coolant system components and component groups.
3-149The applicant's AMRs evaluated and incorporated applicable plant-specific and industry operatingexperience in the determination of AERMs. The plant-specific evaluation included condition reports and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.3.1.2  Staff EvaluationThe staff reviewed LRA Section 3.1 to determine whether the applicant provided sufficientinformation to demonstrate that the effects of aging for the reactor vessel, reactor vessel internals, and reactor coolant system components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRswere consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's audit evaluation are documented in SER Section 3.1.2.1.In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for whichfurther evaluation is recommended. The staff confirmed that the applicant's further evaluations were consistent with the SRP-LR Appendix 3.1.2.2 acceptance criteria. The staff's audit evaluations are documented in SER Section 3.1.2.2.The staff also conducted a technical review of the remaining AMRs that were not consistent with,or not addressed in, the GALL Report. The technical review evaluated whether all plausible aging effects have been identified and whether the aging effects listed were appropriate for the material-environment combinations specified. The staff's evaluations are documented in SER Section 3.1.2.3.For SSCs which the applicant claimed were not applicable or required no aging management, thestaff reviewed the AMR line items and the plant's operating experience to verify the applicant's
 
claims.Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensurethat they provided an adequate description of the programs credited with managing or monitoring aging for the reactor vessel, internals and reactor coolant system components.Table 3.1-1 summarizes the staff's evaluation of components, aging effects/mechanisms, andAMPs listed in LRA Section 3.1 and addressed in the GALL Report.
3-150Table 3.1-1  Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and ReactorCoolant System Components in the GALL ReportComponent Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation Steel pressurevessel support skirt
 
and attachment welds (3.1.1-1)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAAFatigue is aTLAA.(See SER
 
Section 3.1.2.2.1)
Steel; stainlesssteel; steel with nickel-alloy or
 
stainless steel
 
cladding; nickel-alloy reactor vessel components:
flanges; nozzles;
 
penetrations; safe
 
ends; thermal sleeves; vessel
 
shells, heads and welds (3.1.1-2)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c) and environmental
 
effects are to be
 
addressed for Class 1 components TLAAFatigue is aTLAA.(See SER
 
Section 3.1.2.2.1)
Steel; stainlesssteel; steel with nickel-alloy or
 
stainless steel
 
cladding; nickel-alloy RCPB
 
piping, piping
 
components, and
 
piping elements exposed to reactor
 
coolant (3.1.1-3)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c) and environmental
 
effects are to be
 
addressed for Class 1 componentsTLAAFatigue is a TLAA.(See SER Section 3.1.2.2.1)
Steel pump andvalve closure bolting
 
(3.1.1-4)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c) check Code limits for allowable cycles (less than 7000 cycles) of thermal stress
 
rangeTLAAFatigue is a TLAA.(See SER Section 3.1.2.2.1)
Stainless steel andnickel alloy reactor vessel internals
 
components
 
(3.1.1-5)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAAFatigue is a TLAA.(See SER Section 3.1.2.2.1)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-151Nickel alloy tubesand sleeves in a
 
reactor coolant and
 
secondary FW/steam environment
 
(3.1.1-6)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)NoneNot applicable toBWRs Steel and stainlesssteel RCPB closure
 
bolting, head
 
closure studs, support skirts and attachment welds, pressurizer relief
 
tank components, steam generator
 
components, piping
 
and components external surfaces
 
and bolting
 
(3.1.1-7)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)NoneNot applicable toBWRs Steel; stainless steel; and nickel-alloy RCPB
 
piping, piping
 
components, piping
 
elements; flanges; nozzles and safe ends; pressurizer vessel shell heads and welds; heater
 
sheaths and sleeves; penetrations; and thermal sleeves
 
(3.1.1-8)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c) and environmental
 
effects are to be
 
addressed for Class 1 componentsNoneNot applicable toBWRs Steel; stainlesssteel; steel with nickel-alloy or
 
stainless steel
 
cladding; nickel-alloy reactor vessel components:
flanges; nozzles;
 
penetrations;
 
pressure housings;
 
safe ends; thermal sleeves; vessel
 
shells, heads and welds (3.1.1-9)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c) and environmental
 
effects are to be
 
addressed for Class 1 componentsNoneNot applicable toBWRs Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-152 Steel; stainlesssteel; steel with nickel-alloy or
 
stainless steel
 
cladding; nickel-alloy steam
 
generator components (flanges; penetrations; nozzles; safe ends, lower heads and welds)
(3.1.1-10)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c) and environmental
 
effects are to be
 
addressed for Class 1 componentsNoneNot applicable toBWRs Steel top headenclosure (without
 
cladding) top head nozzles (vent, top head spray or reactor core
 
isolation cooling, and spare) exposed
 
to reactor coolant
 
(3.1.1-11)
Loss of material due to general, pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection Program (B.1.21); Inservice
 
Inspection Program (B.1.15.2)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Sections 3.1.2.1.1
 
and 3.1.2.2.2)
Steel steam generator shell assembly exposed to secondary FW
 
and steam (3.1.1-12)
Loss of material due to general, pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionNoneNot applicable toBWRs Steel and stainless steel isolation
 
condenser components exposed to reactor
 
coolant (3.1.1-13)
Loss of material due to general (steel only), pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection Program (B.1.21); Inservice
 
Inspection Program (B.1.15.2)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Sections 3.1.2.1.2
 
and 3.1.2.2.2)
Stainless steel,nickel-alloy, and steel with nickel-alloy or
 
stainless steel
 
cladding reactor vessel flanges,
: nozzles, penetrations, safe ends, vessel shells, heads and welds
 
(3.1.1-14)
Loss of material due to pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection Program (B.1.21); Inservice
 
Inspection Program (B.1.15.2); BWR
 
Vessels Internals
 
Program (B.1.7)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Sections 3.1.2.1.3.
 
and 3.1.2.2.2)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-153 Stainless steel;steel with nickel-alloy or
 
stainless steel
 
cladding; and nickel-alloy RCPB
 
components exposed to reactor
 
coolant (3.1.1-15)
Loss of material due to pitting and crevice corrosionWater Chemistryand One-Time
 
Inspection Water ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection Program (B.1.21); Inservice
 
Inspection Program (B.1.15.2)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Sections 3.1.2.1.4
 
and 3.1.2.2.2)
Steel steam generator upper and lower shell and
 
transition cone exposed to secondary FW and
 
steam (3.1.1-16)
Loss of material due to general, pitting and crevice corrosionInserviceInspection (IWB, IWC, and IWD), and Water Chemistry
 
and, for Westinghouse Model 44 and 51 S/G, if general
 
and pitting corrosion of the shell is known to exist, additional
 
inspection
 
procedures are to be developed.NoneNot applicable toBWRsSteel (with orwithout stainless
 
steel cladding) reactor vessel
 
beltline shell, nozzles, and welds
 
(3.1.1-17)
Loss of fracture toughness due to
 
neutron irradiation
 
embrittlementTLAA, evaluated inaccordance with Appendix G of 10 CFR 50 and RG  1.99. The
 
applicant may
 
choose to demonstrate that
 
the materials of the nozzles are not
 
controlling for the TLAA evaluations.TLAALoss of fracture toughness is a TLAA (See SER
 
Section 3.1.2.1.5)Steel (with orwithout stainless
 
steel cladding) reactor vessel
 
beltline shell, nozzles, and welds; safety injection nozzles (3.1.1-18)
Loss of fracture toughness due to
 
neutron irradiation
 
embrittlementReactor VesselSurveillanceReactor VesselSurveillance
 
Program (B.1.24)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.1.2.2.3)
Stainless steel andnickel alloy top head enclosure vessel
 
flange leak
 
detection line
 
(3.1.1-19)Cracking due toSCC and IGSCC A plant-specificAMP is to be evaluated.Water ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.1.2.2.4)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-154 Stainless steel isolation condenser
 
components exposed to reactor
 
coolant (3.1.1-20)Cracking due toSCC and IGSCCInserviceInspection (IWB, IWC, and IWD),
Water Chemistry, and plant-specific verification programNoneNot applicable (See SER Section 3.1.2.2.4)Reactor vessel shell fabricated of SA508-Cl 2 forgings clad with stainless
 
steel using a
 
high-heat-input welding process
 
(3.1.1-21)Crack growth due tocyclic loadingTLAANoneNot applicable toBWRs Stainless steel andnickel alloy reactor vessel internals
 
components exposed to reactor
 
coolant and neutron
 
flux (3.1.1-22)
Loss of fracture toughness due to
 
neutron irradiation embrittlement, void swellingFSAR supplement commitment to
 
(1) participate in industry RVI aging
 
programs (2) implement
 
applicable results (3) submit for NRC approval > 24
 
months before the extended period an RVI inspection plan
 
based on industry
 
recommendation.NoneNot applicable toBWRs Stainless steelreactor vessel
 
closure head flange
 
leak detection line
 
and bottom-mounted
 
instrument guide
 
tubes (3.1.1-23)Cracking due to SCC A plant-specificAMP is to be evaluated.NoneNot applicable toBWRsClass 1 CASS piping, piping
 
components, and
 
piping elements exposed to reactor
 
coolant (3.1.1-24)Cracking due to SCCWater Chemistryand, for CASS
 
components that do
 
not meet the NUREG-0313
 
guidelines, a plant-specific AMPNoneNot applicable toBWRs Stainless steel jet pump sensing line
 
(3.1.1-25)Cracking due tocyclic loading A plant-specificAMP is to be evaluated.NoneNot applicable (See SER Section 3.1.2.2.8
 
and 3.1.2.3.4)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-155 Steel and stainless steel isolation
 
condenser components exposed to reactor
 
coolant (3.1.1-26)Cracking due tocyclic loadingInserviceInspection (IWB, IWC, and IWD) and
 
plant-specific verification programNoneNot applicable (See SER Section 3.1.2.2.8)
Stainless steel andnickel alloy reactor vessel internals screws, bolts, tie rods, and hold-down
 
springs (3.1.1-27)
Loss of preload dueto stress relaxationFSAR supplement commitment to
 
(1) participate in industry RVI aging
 
programs (2) implement
 
applicable results (3) submit for NRC approval > 24
 
months before the extended period an RVI inspection plan
 
based on industry
 
recommendation.NoneNot applicable toBWRs Steel steam generator FW
 
impingement plate
 
and support exposed to secondary FW
 
(3.1.1-28)
Loss of material due to erosion A plant-specificAMP is to be evaluated.NoneNot applicable toBWRs Stainless steelsteam dryers exposed to reactor
 
coolant (3.1.1-29)Cracking due toflow-induced vibration A plant-specificAMP is to be evaluated.BWR Vessel Internals Program (B.1.7)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Sections 3.1.2.1.6
 
and 3.1.2.2.11)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-156 Stainless steelreactor vessel
 
internals components (e.g., upper internals assembly, rod cluster control assembly guide
 
tube assemblies, baffle/former assembly, lower internal assembly, shroud assemblies, plenum cover and plenum cylinder, upper grid assembly, control
 
rod guide tube assembly, core
 
support shield assembly, core barrel assembly, lower grid assembly, flow distributor assembly, thermal
: shield, instrumentation
 
support structures)
 
(3.1.1-30)Cracking due to
: SCC, irradiation-assisted
 
SCCWater Chemistry and FSAR supplement
 
commitment to
 
(1) participate in industry RVI aging
 
programs (2) implement
 
applicable results (3) submit for NRC approval > 24
 
months before the extended period an RVI inspection plan
 
based on industry
 
recommendation.NoneNot applicable toBWRsNickel alloy andsteel with nickel-alloy cladding
 
piping, piping
 
component, piping
: elements, penetrations, nozzles, safe ends, and welds (other than reactor vessel head); pressurizer
 
heater sheaths, sleeves, diaphragm plate, manways and
 
flanges; core
 
support pads/core
 
guide lugs
 
(3.1.1-31)Cracking due toprimary water stress corrosion crackingInserviceInspection (IWB, IWC, and IWD) and Water Chemistry and FSAR supp
 
commitment to
 
implement applicable plant
 
commitments to (1) NRC Orders, Bulletins, and GLs associated with nickel alloys and
 
(2) staff-accepted industry guidelines.NoneNot applicable toBWRs Steel steamgenerator FW inlet
 
ring and supports
 
(3.1.1-32)Wall thinning due toflow-accelerated corrosion A plant-specificAMP is to be evaluated.NoneNot applicable toBWRs Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-157 Stainless steel andnickel alloy reactor vessel internals
 
components
 
(3.1.1-33)Changes in dimensions due to void swellingFSAR supplement commitment to
 
(1) participate in industry RVI aging
 
programs (2) implement
 
applicable results (3) submit for NRC approval > 24
 
months before the extended period an RVI inspection plan
 
based on industry
 
recommendation.NoneNot applicable toBWRs Stainless steel andnickel alloy reactor
 
CRD head penetration
 
pressure housings
 
(3.1.1-34)Cracking due toSCC and primary water stress corrosion crackingInserviceInspection (IWB, IWC, and IWD) and Water Chemistry and for nickel alloy, comply with applicable NRC Orders and provide
 
a commitment in the FSAR supplement
 
to implement
 
applicable
 
(1) Bulletins and GLs and (2) staff-accepted industry guidelines.NoneNot applicable toBWRsSteel with stainless steel or nickel alloy
 
cladding primary
 
side components;
 
steam generator upper and lower
 
heads, tubesheets
 
and tube-to-tube sheet welds
 
(3.1.1-35)Cracking due toSCC and primary water stress corrosion crackingInserviceInspection (IWB, IWC, and IWD) and Water Chemistry and for nickel alloy, comply with applicable NRC Orders and provide
 
a commitment in the FSAR supplement
 
to implement
 
applicable
 
(1) Bulletins and GLs and (2) staff-accepted industry guidelines.NoneNot applicable toBWRs Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-158Nickel alloy, stainless steel pressurizer spray
 
head (3.1.1-36)Cracking due toSCC and primary water stress corrosion crackingWater Chemistryand One-Time
 
Inspection and, for nickel alloy welded spray heads, comply with applicable NRC Orders and provide
 
a commitment in the FSAR supplement
 
to implement
 
applicable
 
(1) Bulletins and GLs and (2) staff-accepted industry guidelines.NoneNot applicable toBWRs Stainless steel andnickel alloy reactor vessel internals
 
components (e.g., upper internals assembly, rod cluster control assembly guide
 
tube assemblies, lower internal assembly, CEA
 
shroud assemblies, core shroud assembly, core
 
support shield assembly, core barrel assembly, lower grid assembly, flow distributor assembly)
(3.1.1-37)Cracking due toSCC, primary water stress corrosion
: cracking, irradiation-assisted stress corrosion crackingWater Chemistry and FSAR supplement
 
commitment to
 
(1) participate in industry RVI aging
 
programs (2) implement
 
applicable results (3) submit for NRC approval > 24
 
months before the extended period an RVI inspection plan
 
based on industry
 
recommendation.NoneNot applicable toBWRsSteel (with orwithout stainless steel cladding) CRD return line nozzles exposed to reactor
 
coolant (3.1.1-38)Cracking due tocyclic loadingBWR CR DriveReturn Line NozzleBWR CRD ReturnLine Nozzle
 
Program (B.1.2)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1)Steel (with orwithout stainless
 
steel cladding) FW nozzles exposed to
 
reactor coolant
 
(3.1.1-39)Cracking due tocyclic loadingBWR FeedwaterNozzleBWR FeedwaterNozzle Program (B.1.3)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-159 Stainless steel and nickel alloy
 
penetrations for CRD stub tubes
 
instrumentation, jet
 
pump instrumentation, standby liquid control, flux monitor, and drain line exposed to reactor
 
coolant (3.1.1-40)Cracking due toSCC, IGSCC, cyclic
 
loadingBWR Penetrationsand Water ChemistryWater ChemistryControl-BWR (B.1.30.2); BWR
 
Penetrations
 
Program (B.1.4);
BWR Vessel
 
Internals (B.1.7);
Inservice Inspection
 
Program (B.1.15.2)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1.7)
Stainless steel andnickel alloy piping, piping components, and piping elements
 
greater than or
 
equal to 4 inches NPS; nozzle safe
 
ends and associated welds
 
(3.1.1-41)Cracking due toSCC and IGSCCBWR StressCorrosion Cracking and Water ChemistryBWR StressCorrosion Cracking
 
Program (B.1.5);
Water Chemistry Control-BWR
 
Program (B.1.30.2);
Inservice Inspection
 
Program (B.1.15.2);
One-Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1.8)
Stainless steel andnickel alloy vessel
 
shell attachment welds exposed to
 
reactor coolant
 
(3.1.1-42)Cracking due toSCC and IGSCCBWR Vessel IDAttachment Welds and Water ChemistryBWR Vessel IDAttachment Welds
 
Program (B.1.6);
Water Chemistry Control-BWR
 
Program (B.1.30.2)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1)
Stainless steel fuelsupports and CRD assemblies CRD housing exposed to
 
reactor coolant
 
(3.1.1-43)Cracking due toSCC and IGSCCBWR VesselInternals and Water ChemistryBWR Vessel Internals Program (B.1.7); Water Chemistry Control-BWR
 
Program (B.1.30.2)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1)
Stainless steel andnickel alloy core
 
shroud, core plate, core plate bolts, support structure, top guide, CS lines, spargers, jet pump assemblies, CRD
 
housing, nuclear
 
instrumentation
 
guide tubes
 
(3.1.1-44)Cracking due to SCC, IGSCC, irradiation-assisted stress corrosion crackingBWR VesselInternals and Water ChemistryBWR Vessel Internals Program (B.1.7); Water Chemistry Control-BWR
 
Program (B.1.30.2)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1.9)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-160 Steel piping, piping components, and
 
piping elements exposed to reactor
 
coolant (3.1.1-45)Wall thinning due toflow-accelerated corrosionFlow-AcceleratedCorrosionFlow-AcceleratedCorrosion Program (B.1.13)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1)Nickel alloy core shroud and core
 
plate access hole cover (mechanical covers)
(3.1.1-46)Cracking due to SCC, IGSCC, irradiation-assisted stress corrosion crackingInserviceInspection (IWB, IWC, and IWD), and Water ChemistryNoneConsistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.3.4 Stainless steel andnickel-alloy reactor vessel internals exposed to reactor
 
coolant (3.1.1-47)
Loss of material due to pitting and crevice corrosionInserviceInspection (IWB, IWC, and IWD), and Water ChemistryOne-Time Inspection Program (B.1.15.2); Water Chemistry Control-BWR
 
Program (B.1.30.2)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1.10)
Steel and stainlesssteel Class 1 piping, fittings and branch
 
connections < 4 inches NPS exposed to reactor
 
coolant (3.1.1-48)Cracking due toSCC, IGSCC (for stainless steel only),
and thermal and
 
mechanical loadingInserviceInspection (IWB, IWC, and IWD),
Water chemistry, and One-Time Inspection of ASME Code Class 1
 
Small-bore PipingInservice Inspection Program (B.1.15.2);
One-Time Inspection Program (B.1.21); Water Chemistry Control-BWR
 
Program (B.1.30.2)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1.11)Nickel alloy core shroud and core
 
plate access hole cover (welded covers)
(3.1.1-49)Cracking due to SCC, IGSCC, irradiation-assisted stress corrosion crackingInserviceInspection (IWB, IWC, and IWD),
Water Chemistry, and, for BWRs with a crevice in the access hole covers, augmented inspection using UT
 
or other demonstrated
 
acceptable
 
inspection of the access hole cover weldsBWR Vessel Internals Program (B.1.7); Water Chemistry Control-BWR
 
Program (B.1.30.2)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1.12)High-strength lowalloy steel top head
 
closure studs and nuts exposed to air with reactor coolant
 
leakage (3.1.1-50)Cracking due toSCC and IGSCCReactor HeadClosure StudsReactor HeadClosure Studs
 
Program (B.1.23);
Inservice Inspection
 
Program (B.1.15.2)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1.13)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-161CASS jet pumpassembly castings;
 
orificed fuel support
 
(3.1.1-51)
Loss of fracture toughness due to
 
thermal aging and
 
neutron irradiation
 
embrittlementThermal Aging andNeutron Irradiation
 
Embrittlement of
 
CASSThermal Aging andNeutron Irradiation
 
Embrittlement of
 
CASS Program (B.1.29)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1)
Steel and stainlesssteel RCPB pump and valve closure bolting, manway
 
and holding bolting, flange bolting, and
 
closure bolting in
 
high-pressure and
 
high-temperature systems (3.1.1-52)Cracking due toSCC, loss of
 
material due to wear, loss of
 
preload due to
 
thermal effects, gasket creep, and
 
self-looseningBolting IntegrityBolting Integrity ProgramConsistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1.14)
Steel piping, piping components, and
 
piping elements exposed to closed cycle cooling water
 
(3.1.1-53)
Loss of material due to general, pitting and crevice corrosionClosed-CycleCooling Water SystemNoneNot applicable. (There are no steel
 
components of the Class 1 reactor vessel, vessel internals or RCPB exposed to closed cycle cooling water.)
(See SER Section 3.1.2.3.4)Copper alloy piping, piping components, and piping elements exposed to closed cycle cooling water
 
(3.1.1-54)
Loss of material dueto pitting, crevice, and galvanic corrosionClosed-CycleCooling Water SystemNoneNot applicable.(There are no
 
copper alloy
 
components of the Class 1 reactor vessel, vessel internals or RCPB exposed to closed cycle cooling water.)
(See SER Section 3.1.2.3.4)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-162CASS Class 1 pumpcasings, and valve
 
bodies and bonnets exposed to reactor
 
coolant > 250C (> 482F)(3.1.1-55)
Loss of fracture toughness due to
 
thermal aging
 
embrittlementInserviceinspection (IWB, IWC, and IWD).
Thermal aging
 
susceptibility
 
screening is not necessary, inservice
 
inspection
 
requirements are
 
sufficient for
 
managing these aging effects. ASME Code Case N-481 also provides an alternative for pump
 
casings.Inservice Inspection Program (B.1.15.2);
One-Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.1.2.1.15)Copper alloy > 15 percent Zn piping, piping components, and piping elements exposed to closed cycle cooling water
 
(3.1.1-56)
Loss of material dueto selective leachingSelective Leachingof MaterialsNoneNot applicable(There are no steel
 
components of the Class 1 reactor vessel, vessel internals or RCPB exposed to closed cycle cooling water.)
(See SER Section 3.1.2.3.4)CASS Class 1 piping, piping
 
component, and
 
piping elements and CRD pressure housings exposed
 
to reactor coolant
 
> 250C (> 482F)(3.1.1-57)
Loss of fracture toughness due to
 
thermal aging
 
embrittlementThermal Aging Embrittlement of
 
CASSOne-Time Inspection Program (B.1.21) (See SER Section 3.1.2.1.16)Steel RCPBexternal surfaces exposed to air with borated water
 
leakage (3.1.1-58)
Loss of material due to Boric acid corrosionBoric AcidCorrosionNoneNot applicable toBWRs Steel steam generator steam nozzle and safe end, FW nozzle and safe end, auxiliary feedwater nozzles
 
and safe ends exposed to
 
secondary FW/steam (3.1.1-59)Wall thinning due toflow-accelerated corrosionFlow-AcceleratedCorrosionNoneNot applicable toBWRs Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-163 Stainless steel fluxthimble tubes (with or without chrome
 
plating)
(3.1.1-60)
Loss of material dueto WearFlux Thimble Tube InspectionNoneNot applicable toBWRs Stainless steel,steel pressurizer
 
integral support exposed to air with
 
metal temperature
 
up to 288C (550F)(3.1.1-61)Cracking due tocyclic loadingInserviceInspection (IWB, IWC, and IWD)NoneNot applicable toBWRs Stainless steel,steel with stainless
 
steel cladding
 
reactor coolant system cold leg, hot
 
leg, surge line, and spray line piping and fittings exposed
 
to reactor coolant
 
(3.1.1-62)Cracking due tocyclic loadingInserviceInspection (IWB, IWC, and IWD)NoneNot applicable toBWRsSteel reactor vessel flange, stainless
 
steel and nickel alloy reactor vessel internals exposed to
 
reactor coolant (e.g., upper and lower internals assembly, CEA shroud assembly, core support barrel, upper grid assembly, core
 
support shield assembly, lower grid assembly)
(3.1.1-63)
Loss of material dueto WearInserviceInspection (IWB, IWC, and IWD)NoneNot applicable toBWRs Stainless steel andsteel with stainless
 
steel or nickel alloy cladding pressurizer
 
components
 
(3.1.1-64)Cracking due toSCC, primary water stress corrosion crackingInserviceInspection (IWB, IWC, and IWD) and Water ChemistryNoneNot applicable toBWRs Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-164Nickel alloy reactorvessel upper head and CRD penetration nozzles, instrument tubes, head vent pipe (top head), and welds
 
(3.1.1-65)Cracking due toprimary water stress corrosion crackingInserviceInspection (IWB, IWC, and IWD) and Water Chemistry and Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water ReactorsNoneNot applicable toBWRs Steel steam generator secondary manways
 
and handholds (cover only) exposed to air with
 
leaking secondary-side water and/or steam
 
(3.1.1-66)
Loss of material due to erosionInserviceInspection (IWB, IWC, and IWD) for Class 2 componentsNoneNot applicable toBWRsSteel with stainless steel or nickel alloy
 
cladding; or
 
stainless steel pressurizer
 
components exposed to reactor
 
coolant (3.1.1-67)Cracking due tocyclic loadingInserviceInspection (IWB, IWC, and IWD), and Water ChemistryNoneNot applicable toBWRs Stainless steel,steel with stainless
 
steel cladding Class 1 piping, fittings, pump casings, valve bodies, nozzles, safe ends, manways, flanges, CRD housing; pressurizer heater sheaths, sleeves, diaphragm plate; pressurizer relief
 
tank components, reactor coolant system cold leg, hot
 
leg, surge line, and spray line piping
 
and fittings
 
(3.1.1-68)Cracking due to SCCInserviceInspection (IWB, IWC, and IWD), and Water ChemistryNoneNot applicable toBWRs Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-165 Stainless steel,nickel alloy safety injection nozzles, safe ends, and associated welds
 
and buttering exposed to reactor
 
coolant (3.1.1-69)Cracking due toSCC, primary water stress corrosion crackingInserviceInspection (IWB, IWC, and IWD), and Water ChemistryNoneNot applicable toBWRs Stainless steel;steel with stainless
 
steel cladding Class 1 piping, fittings and branch
 
connections < 4
 
inches NPS exposed to
 
reactor coolant
 
(3.1.1-70)Cracking due toSCC, thermal and
 
mechanical loadingInserviceInspection (IWB, IWC, and IWD),
Water chemistry, and One-Time Inspection of ASME Code Class 1
 
Small-bore PipingNoneNot applicable toBWRsHigh-strength lowalloy steel closure
 
head stud assembly exposed to air with
 
reactor coolant
 
leakage (3.1.1-71)Cracking due toSCC; loss of material due to wearReactor HeadClosure StudsNoneNot applicable toBWRsNickel alloy steam generator tubes and sleeves exposed to
 
secondary FW/steam (3.1.1-72)Cracking due toOD SCC and
 
intergranular attack, loss of material due to fretting and wearSteam GeneratorTube Integrity and Water ChemistryNoneNot applicable toBWRsNickel alloy steam generator tubes, repair sleeves, and tube plugs exposed
 
to reactor coolant
 
(3.1.1-73)Cracking due toprimary water stress corrosion crackingSteam GeneratorTube Integrity and Water ChemistryNoneNot applicable toBWRsChrome plated steel, stainless
 
steel, nickel alloy
 
steam generator anti-vibration bars exposed to
 
secondary FW/steam (3.1.1-74)Cracking due toSCC, loss of
 
material due to crevice corrosion
 
and frettingSteam GeneratorTube Integrity and Water ChemistryNoneNot applicable toBWRs Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-166Nickel alloy once-through steam
 
generator tubes exposed to
 
secondary FW/steam (3.1.1-75)Denting due to corrosion of carbon
 
steel tube support
 
plateSteam GeneratorTube Integrity and Water ChemistryNoneNot applicable toBWRs Steel steam generator tube
 
support plate, tube bundle wrapper exposed to
 
secondary FW/steam (3.1.1-76)
Loss of material due to erosion, general, pitting, and crevice
 
corrosion, ligament
 
cracking due to corrosionSteam GeneratorTube Integrity and Water ChemistryNoneNot applicable toBWRsNickel alloy steam generator tubes and sleeves exposed to
 
phosphate chemistry in
 
secondary FW/steam (3.1.1-77)
Loss of material dueto wastage and
 
pitting corrosionSteam GeneratorTube Integrity and Water ChemistryNoneNot applicable toBWRs Steel steam generator tube
 
support lattice bars exposed to
 
secondary FW/steam (3.1.1-78)Wall thinning due toflow-accelerated corrosionSteam GeneratorTube Integrity and Water ChemistryNoneNot applicable toBWRsNickel alloy steam generator tubes exposed to
 
secondary FW/steam (3.1.1-79)Denting due to corrosion of steel
 
tube support plateSteam GeneratorTube Integrity; Water Chemistry
 
and, for plants that could experience
 
denting at the upper
 
support plates, evaluate potential
 
for rapidly
 
propagating cracks and then develop and take corrective
 
actions consistent with Bulletin 88-02.NoneNot applicable toBWRs Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-167CASS reactorvessel internals (e.g., upper internals assembly, lower internal assembly, CEA
 
shroud assemblies, control rod guide tube assembly, core
 
support shield assembly, lower grid assembly)
(3.1.1-80)
Loss of fracture toughness due to
 
thermal aging and
 
neutron irradiation
 
embrittlementThermal Aging andNeutron Irradiation
 
Embrittlement of
 
CASSNoneNot applicable toBWRsNickel alloy ornickel-alloy clad
 
steam generator divider plate exposed to reactor
 
coolant (3.1.1-81)Cracking due toprimary water stress corrosion crackingWater ChemistryNoneNot applicable toBWRs Stainless steel steam generator primary side divider plate exposed to
 
reactor coolant
 
(3.1.1-82)Cracking due to SCCWater ChemistryNoneNot applicable toBWRs Stainless steel;steel with nickel-alloy or
 
stainless steel
 
cladding; and nickel-alloy reactor vessel internals and RCPB components exposed to reactor
 
coolant (3.1.1-83)
Loss of material due to pitting and crevice corrosionWater ChemistryNoneNot applicable toBWRsNickel alloy steam generator components such as, secondary side nozzles (vent, drain, and
 
instrumentation) exposed to
 
secondary FW/steam (3.1.1-84)Cracking due to SCCWater Chemistryand One-Time
 
Inspection or Inservice Inspection (IWB, IWC, and IWD).NoneNot applicable toBWRs Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-168Nickel alloy piping, piping components, and piping elements exposed to air -
 
indoor uncontrolled (external)
 
(3.1.1-85)NoneNoneNoneConsistent with GALL Report ( See
 
SER Section 3.1.2.1)
Stainless steel piping, piping
 
components, and
 
piping elements exposed to air -
 
indoor uncontrolled (External); air with borated water
 
leakage; concrete;
 
gas (3.1.1-86)NoneNoneNoneConsistent with GALL Report ( See
 
SER Section 3.1.2.1)
Steel piping, piping components, and
 
piping elements in
 
concrete (3.1.1-87)NoneNoneNoneNot applicable(There are no
 
components of the Class 1 reactor vessel, vessel internals or RCPB exposed to
 
concrete.)The staff's review of the reactor vessel, reactor vessel internals, and reactor coolant systemcomponent groups followed any one of several approaches. One approach, documented in SER Section 3.1.2.1, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.1.2.2, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.1.2.3, reviewed AMR results for components that the applicant indicated are not consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the reactor vessel, reactor vessel internals, and reactor coolant system components is documented in SER Section 3.0.3.3.1.2.1  AMR Results Consistent with the GALL ReportSummary of Technical Information in the Application. LRA Section 3.1.2.1 identifies the materials,environments, AERMs, and the following programs that manage aging effects for the reactor vessel, reactor vessel internals, and reactor coolant system components:
* BWR Control Rod Drive Return Line Nozzle Program
* BWR Feedwater Nozzle Program
* BWR Penetrations Program
* BWR Stress Corrosion Cracking Program 3-169
* BWR Vessel Inside Diameter Attachment Welds Program
* BWR Vessel Internals Program
* Flow-Accelerated Corrosion Program
* Inservice Inspection Program
* One-Time Inspection Program
* Reactor Head Closure Studs Program
* Reactor Vessel Surveillance Program
* System Walkdown Program
* Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless SteelProgram
* Water Chemistry Control - BWR Program
* Water Chemistry Control - Closed Cooling Water ProgramStaff Evaluation. LRA Tables 3.1.2-1 through 3.1.2-3 summarize AMRs for the reactor vessel,reactor vessel internals, and reactor coolant system components and indicate AMRs claimed to be consistent with the GALL Report.For component groups evaluated in the GALL Report for which the applicant claimed consistencywith the report and for which it does not recommend further evaluation, the staff's audit and review determined whether the plant-specific components of these GALL Report component groups were bounded by the GALL Report evaluation.The applicant noted for each AMR line item how the information in the tables aligns with theinformation in the GALL Report. The staff audited those AMRs with notes A through E indicating how the AMR is consistent with the GALL Report.Note A indicates that the AMR line item is consistent with the GALL Report for component,material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP.
The staff audited these line items to verify consistency with the GALL Report and validity of the AMR for the site-specific conditions.Note B indicates that the AMR line item is consistent with the GALL Report for component,material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify consistency with the GALL Report and verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also determines whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions.Note C indicates that the component for the AMR line item, although different from, is consistentwith the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified in the GALL Report a different component with the same material, environment, aging effect, and AMP as the component under review. The staff audited these line items to verify consistency with the GALL Report. The staff also determines whether the AMR line item of the different component was applicable to the component under review and whether the AMR was valid for the site-specific conditions.
3-170Note D indicates that the component for the AMR line item, although different from, is consistentwith the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component was applicable to the component under review and whether the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also determines whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions.Note E indicates that the AMR line item is consistent with the GALL Report for material,environment, and aging effect, but credits a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also determines whether the credited AMP would manage the aging effect consistently with the GALL AMP and whether the AMR was valid for the site-specific conditions.
The staff audited and reviewed the information in the LRA. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs.The staff reviewed the LRA to confirm that the applicant: (a) provided a brief description of thesystem, components, materials, and environments; (b) stated that the applicable aging effects were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the reactor vessel, reactor vessel internals, and reactor coolant system components that are subject to an AMR. On the basis of its audit and review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.1.1, the applicant's references to the GALL Report are acceptable and no further staff review is required.3.1.2.1.1  Loss of Material Due to General, Pitting and Crevice Corrosion In the discussion column of LRA Table 3.1.1, Item 3.1.1-11, the applicant stated that the WaterChemistry Control-BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in carbon steel components of the reactor vessel. The Inservice Inspection Program supplements the applicant's Water Chemistry Control-BWR Program for components.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in LRA Tables 3.1.2-1 to 3.1.2-3. The staff reviewed the applicant's Water Chemistry Control - BWR Program, One-Time Inspection Program, and Inservice Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11, 3.0.3.1.6, and 3.0.3.3.3, respectively. The staff found each program acceptable. During interviews with the applicant's technical personnel, the staff confirmed that the applicantincluded all components in LRA Table 3.1.1, Item 3.1.1-11 in the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore is acceptable.
3-171On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.The staff evaluated the applicant's claim of consistency with the GALL Report. The staff alsoreviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed consistent with its AMRs. Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.1.2  Loss of Material Due to General (Steel Only), Pitting and Crevice Corrosion In the discussion column of LRA Table 3.1.1, Item 3.1.1-13, the applicant stated that WaterChemistry Control-BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in carbon steel components of the reactor vessel. The Inservice Inspection Program supplements the applicant's Water Chemistry Control-BWR Program for certain of these components.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in LRA Tables 3.1.2-1 to 3.1.2-3. The staff reviewed the applicant's Water Chemistry Control - BWR Program, One-Time Inspection Program, and Inservice Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11, 3.0.3.1.6, and 3.0.3.3.3, respectively. The staff found each program acceptable.During interviews with the applicant's technical personnel, the staff confirmed that the applicantincluded all components in LRA Table 3.1.1, Item 3.1.1-13 in the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore is acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.1.2.1.3  Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.1.1, Item 3.1.1-14, the applicant stated that the WaterChemistry Control-BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in carbon steel components of the reactor vessel. Either the Inservice Inspection Program or the BWR Vessel Internals Program supplements the applicant's Water Chemistry Control-BWR Program for certain of these components.
3-172During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in LRA Tables 3.1.2-1 to 3.1.2-3. The staff reviewed the applicant's Water Chemistry Control - BWR Program, One-Time Inspection Program, Inservice Inspection Program, and BWR Vessel Internals Program. These evaluations are documented in SER Sections 3.0.3.1.11, 3.0.3.1.6, 3.0.3.3.3, and 3.0.3.2.7, respectively. The staff found each program acceptable.During interviews with the applicant's technical personnel, the staff confirmed that the applicantincluded all components in LRA Table 3.1.1, Item 3.1.1-14 in the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore is acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.1.2.1.4  Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.1.1, Item 3.1.1-15, the applicant stated that the WaterChemistry Control-BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in carbon steel components of the reactor vessel. The Inservice Inspection Program supplements the applicant's Water Chemistry Control-BWR Program for certain of these components.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified. The staff reviewed the applicant's Water Chemistry Control
- BWR Program, One-Time Inspection Program, and Inservice Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11, 3.0.3.1.6, and 3.0.3.3.3, respectively.
The staff found each program acceptable.During interviews with the applicant's technical personnel, the staff confirmed that the applicantincluded all components in LRA Table 3.1.1, Item 3.1.1-15 in the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore is acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.1.2.1.5  Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement In the discussion column of LRA Table 3.1.1, Item 3.1.1-17, the applicant stated that loss offracture toughness for the reactor vessel beltline shell and welds is a TLAA.During the audit and review, the staff noted that the applicant's controlling documentation formaterials in the nozzles leading to the vessel lacked sufficient calculations and accountability for errors. In accordance with  Regulatory Guide (RG ) 1.190, "Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence," analytic uncertainty is to be considered in the calculation of fluence. The staff further noted that in the applicant's NSSS supplier document, GE-NE-000-0007-2342-R1-NP (dated July 2003), "Entergy Northeast Vermont Yankee Neutron 3-173Flux Evaluation," flux variations of up to but less than 19 percent were considered. During theaudit and review, the applicant provided extrapolated data for determining if the top of the recirculation inlet nozzles might experience an extended power uprate fluence of greater than 1X10 17 n/cm 2.In RAI 3.1.1-17-P-01, the staff asked the applicant if a maximum variation of approximately 19percent was considered in this extrapolated data. If not, what calculated fluence level that could be experienced by the top of the recirculation inlet nozzles if the applicant considered a maximum flux variation of just less than 19 percent.In its response, by letter dated September 5, 2006, the applicant stated that a 19 percentuncertainty was not added to the fluence value in determining whether the nozzle (nozzle to vessel weld) would exceed 1X10 17 n/cm 2 (E greater than 1 MeV). The applicant further stated thatthe fluence was extrapolated to determine the height at which fluence would equal 1 x10 17 n/cm 2rather than to specifically estimate the fluence at the nozzle.The applicant also stated that the projected fluence in this region changes rapidly with elevation.The projected 1/4 T fluence at the bottom of the active fuel is 0.985 X10 17 n/cm 2, and 5.5 incheslower, at the nozzle to vessel weld, the estimated fluence is 0.66 X10 17 n/cm 2. The applicantstated that if the fluence is increased by 19 percent to cover possible error in the analysis, the fluence at the nozzle to vessel weld would be 0.792 X10 17 n/cm 2. Therefore, the recirculationinjection nozzles, and their welds, remain below the 1X10 17 n/cm 2 threshold for the period ofextended operation.The staff reviewed the GE fluence calculations, GE-NE-000-0007-2342-R1-NP, in conjunctionwith RAI 4.2-1. The staff's evaluation of this TLAA is documented in SER Section 4.2. The staff found the applicant's response acceptable because the applicant used up to 19 percent flux variations in its fluence calculation. The staff's concern described in RAI 3.3.1-17-P-01 is resolved.3.1.2.1.6  Cracking Due to Flow-Induced Vibration In the discussion column of LRA Table 3.1.1, Item 3.1.1-29, the applicant stated that the BWRVessel Internals Program will manage cracking in the stainless steel steam dryers.During the audit and review, the staff asked the applicant for additional information on the AMP.VYNPS technical personnel stated that a steam dryer monitoring plan had been submitted as part of the power uprate application and approved by the staff. In addition, BWRVIP-139, "Steam Dryer Inspection and Flaw Evaluation Guidelines," has been submitted to the NRC for review and approval. It is expected that this BWRVIP will be approved by the NRC prior to the period of extended operation and as such will become a part of the BWR Vessel Internals Program.
VYNPS will manage cracking of the steam dryers per the BWR Vessel Internals Program during the period of extended operation. Exceptions, if any, will be subject to review and approval by the staff.
3-174The staff finds that since the applicant committed (Commitment #37) to implement BWRVIP-139as approved by the staff, if the staff does approve BWRVIP-139, this aging effect/mechanism will be adequately managed as recommended by the GALL Report. If the staff does not issue an SER approving the use of BWRVIP-139, a plant-specific program must be submitted at least 24 months prior to the period of extended operation for review and approval.3.1.2.1.7  Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking,Cyclic LoadingIn the discussion column of LRA Table 3.1.1, Item 3.1.1-40, the applicant stated that cracking instainless steel and nickel-alloy nozzles and penetrations in the reactor vessel is managed by the Water Chemistry Control-BWR Program and either BWR Penetrations Program, BWR Vessel Internals Program, or Inservice Inspection Program.The applicant also stated that cracking of the nickel-based alloy CRD stub tubes is managedusing the BWR Vessel Internals Program and the Water Chemistry Control - BWR Program.The staff reviewed the applicant's BWR Vessel Internals Program. This evaluation is documentedin SER Section 3.0.3.2.7. The staff finds that inspection guidance for the CRD stub tubes is included in BWRVIP-47, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines," which has been reviewed and accepted by the staff. Because the BWR Vessel Internals Program incorporates the applicable guidelines of BWRVIP-47, the staff finds it to be an acceptable method for aging management of cracking of the CRD stub tubes.The applicant also stated that stainless steel incore housings are managed using the InserviceInspection Program and the Water Chemistry Control - BWR Program.The staff reviewed the applicant's Inservice Inspection Program. This evaluation is documented inSER Section 3.0.3.3.3. The program is plant-specific and incorporates the inspection requirements of ASME Code, Section XI in accordance with 10 CFR 50.55a. Because the Inservice Inspection Program provides for inspections that satisfy the requirements of the ASME Code as reviewed and accepted by the staff, the staff finds it to be an acceptable method for aging management of cracking of the incore housings.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.1.2.1.8  Cracking Due to Stress Corrosion Cracking and Intergranular Stress CorrosionCrackingIn LRA Table 3.1.1, Item 3.1.1-41, the applicant stated that cracking in stainless steel andnickel-alloy piping, nozzle safe ends, and associated welds is managed by its Water Chemistry Control - BWR Program and the BWR Stress Corrosion Cracking Program. Cracking due to SCC and IGSCC is managed in this way for stainless steel safe ends on recirculation nozzles (inlet and outlet) and jet pump instrument nozzles as well as nickel-based alloy safe ends for CS.
3-175In LRA Table 3.1.2-3, for pump casings and valve bodies of CASS, as well as piping, fittings, flowelements, and thermowells of stainless steel, the applicant augments the BWR Stress Corrosion Cracking Program and the Water Chemistry Programs with the Inservice Inspection Program.
This meets the recommendations of the GALL Report for this item and is acceptable to the staff.The applicant also stated that other component types associated with this item but outside thescope of the BWR Stress Corrosion Cracking Program are to be managed using the Inservice Inspection Program and the Water Chemistry Control - BWR Program. Cracking is managed in this manner for stainless-steel-clad nozzles of low-alloy steel (recirculation, CS, head spray, head instrumentation, head vent, and jet pump instrument nozzles); nickel-based alloy flange leakoff nozzles; stainless steel head nozzle flanges, blank flanges, as well as safe ends for the
 
SLC/P and instrumentation nozzles. Low-alloy steel is not susceptible to SCC and componentsless than 4 inches nominal pipe size (NPS) are not within the scope of the BWR Stress Corrosion Cracking Program. The FWthermal sleeves of stainless steel and nickel-based alloy are also managed using the Inservice Inspection Program and the Water Chemistry Control - BWR Program.During the audit and review, the staff asked the applicant's technical personnel to clarify how theFW inlet thermal sleeves can be managed with the Inservice Inspection - Inservice Inspection Program. The applicant's technical personnel stated that the VYNPS thermal sleeves are not welded in place, but rather they are installed with an interference fit. As such, there is no weld to the pressure boundary piping that can be examined by the Inservice Inspection Program. The applicant's technical personnel further stated that because there is no pressure boundary weld, these sleeves are not part of the pressure boundary. By letter dated July 14, 2006, the applicant revised LRA Table 3.1.2-1 to remove all line items for the "Thermal Sleeves Feedwater Inlets (N4)" component type.Interference fitted thermal sleeves are not subject to SCC and IGSCC. The thermal sleeves aremanaged using the Water Chemistry Control - BWR Program. On this basis, the staff determines that the aging of the thermal sleeves is adequately managed.The staff reviewed the applicant's Inservice Inspection Program. This evaluation is documented inSER Section 3.0.3.3.3. The staff found the program acceptable. The program is plant-specific and incorporates the inspection requirements of ASME Code, Section XI in accordance with 10 CFR 50.55a.Because the Inservice Inspection Program provides for inspections to satisfy the requirements ofthe ASME Code as reviewed and accepted by the staff, the staff finds it to be an acceptable method for management of cracking of these components.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
3-1763.1.2.1.9  Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking,Irradiation-Assisted Stress Corrosion CrackingIn the discussion column of LRA Table 3.1.1, Item 3.1.1-44, the applicant stated that crackingdue to SCC, IGSCC, and IASCC in the CASS, stainless steel, and nickel-based alloy components internal to the reactor vessel is to be managed using the BWR Vessel Internals Program and the Water Chemistry Control-BWR Program. The applicant included access hole cover plates among these items, for which the GALL Report recommends augmented inspection using the Inservice Inspection Program if the plate is mechanically fastened or welded in such a way that a crevice is formed.In the LRA, the applicant stated that the access hole covers are welded in place, notmechanically fastened, and that they were welded in a manner that prevented the formation of a crevice.The staff reviewed the applicant's BWR Vessel Internals Program and Water ChemistryControl-BWR Program. These evaluations are documented in SER Sections 3.0.3.2.7 and 3.0.3.1.11, respectively. The staff found each program acceptable. Management of cracking due to SCC, IGSCC, and IASCC of these components is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.1.2.1.10  Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.1.1, Item 3.1.1-47, the applicant stated that loss ofmaterial in stainless steel and nickel-alloy components of the reactor vessel internals is managedby the Water Chemistry Control-BWR Program. The One-Time Inspection Program will verify the effectiveness of the applicant's Water Chemistry Control-BWR Program to manage loss of material. The applicant's Inservice Inspection Program is not applicable to most reactor vessel internals components since they are not part of the pressure boundary. Management of loss of material using the applicant's Water Chemistry Control-BWR Program augmented by its One-Time Inspection Program is consistent with similar items in LRA Table 3.1.1.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in LRA Tables 3.1.2-1 to 3.1.2-3. The staff reviewed the applicant's Water Chemistry Control - BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable.During interviews with the applicant's technical personnel, the staff confirmed that the applicantincluded all components in LRA Table 3.1.1, Item 3.1.1-47 in the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
3-1773.1.2.1.11  Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking(For Stainless Steel Only), and Thermal and Mechanical LoadingIn the discussion column of LRA Table 3.1.1, Item 3.1.1-48, the applicant stated that cracking ofClass 1 stainless steel components less than 4 inches NPS is managed by the Water Chemistry Control-BWR Program and the One-Time Inspection Program.The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-TimeInspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable.The staff asked the applicant to justify the omission of ISI from the management of aging forClass 1 components. By letter dated July 14, 2006, the applicant revised LRA Table 3.1.2-3 to apply the Inservice Inspection Program, in addition to the Water Chemistry Control - BWR Program and One-Time Inspection Program, to manage cracking for all component types of piping and fittings less than 4 inches NPS, with the exception of the head seal leak detection line.
With this change, the staff finds the applicant's management of cracking due to SCC, IGSCC, and thermal and mechanical loading of steel and stainless steel Class 1 piping, fittings, andbranch connections less than 4 inches NPS consistent with the GALL Report and therefore acceptable.The staff also asked the applicant for confirmation that CRD accumulators and condensing potswere less than 4 inches NPS and appropriate for inclusion with this item of LRA Table 3.1.1.The applicant stated that these components are connected using tubing less than 4 inches NPSand are outside the scope of the its Inservice Inspection Program.The staff reviewed the ISI database to confirm that these items are not in the scope of theapplicant's Inservice Inspection Program, and concludes that the use of the Water Chemistry Control-BWR Program and the One-Time Inspection Program to manage cracking of these components is appropriate.Cracking due to SCC, IGSCC and thermal and mechanical loading of stainless steel CRD drivesexposed to treated water greater than 270F in the RCPB is to be managed using "InserviceInspection Program."The staff's review of the applicant's Inservice Inspection Program is documented in SERSection 3.0.3.3.3, which the staff found acceptable. The staff finds that this program satisfies the criteria of SRP-LR Appendix A.1 for stainless steel CRD drives in the RCPB and is therefore acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
3-1783.1.2.1.12  Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking,Irradiation-Assisted Stress Corrosion CrackingIn the discussion column of LRA Table 3.1.1, Item 3.1.1-49, the applicant stated that VYNPS haswelded access hole covers with no crevice behind the weld. Cracking of the nickel-alloy shroud support access hole covers is managed by "BWR Vessel Internals Program," and "Water Chemistry Control-BWR Program," as described in LRA Table 3.1.1, Item 3.1.1-44. The staff's evaluation of this AMR is documented in SER Section 3.1.2.1.9.On the basis of its review, the staff finds that augmented inspection of the access hole covers isnot required to adequately manage this aging effect/mechanism and that management of cracking of the core shroud and core plate access hole cover is consistent with the recommendations of the GALL Report and is therefore acceptable.3.1.2.1.13  Cracking Due to Stress Corrosion Cracking and Intergranular Stress CorrosionCrackingIn the discussion column of LRA Table 3.1.1, Item 3.1.1-50, the applicant stated that the ReactorHead Closure Studs Program manages cracking in low alloy steel head closure flange bolting while the Inservice Inspection Program manages cracking in other low-alloy steel bolting of the RCS pressure boundary.The staff reviewed the applicant's Reactor Head Closure Studs Program and Inservice InspectionProgram. These evaluations are documented in SER Sections 3.0.3.2.14 and 3.0.3.3.3, respectively. The staff found each program acceptable.The staff noted that the applicant was managing cracking of other low alloy steel pressureboundary bolting (i.e., flange bolts and nuts [N6A, N6B, N7] and CRD flange capscrews and washers) with the Inservice Inspection Program. The staff asked the applicant to clarify how aging of steel and stainless steel bolting would be adequately managed in the absence of aBolting Integrity Program. In a letter dated July 6, 2006, the applicant committed (Commitment
#34) to prepare and submit an AMP consistent with GALL AMP XI.M18, "Bolting Integrity," for approval. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staff's evaluation of this program is documented in SER Section 3.0.3.2.19. With this AMP, the staff finds that the applicant's management of cracking of other low alloy steel bolting will be consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant, with the Commitment #34 identifiedabove, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.1.2.1.14  Cracking Due to Stress Corrosion Cracking, Loss of Material Due to Wear, Loss ofPreload Due to Thermal Effects, Gasket Creep, and Self-LooseningIn the discussion column of LRA Table 3.1.1, Item 3.1.1-52, the applicant stated that crackingdue to SCC, loss of material due to wear, loss of preload due to thermal effects, gasket creep, and self-loosening is to be managed using the Inservice Inspection Program.
3-179The staff reviewed the applicant's Inservice Inspection Program. This evaluation is documented inSER Section 3.0.3.3.3 and was found acceptable by the staff.During the audit and review, the staff asked the applicant to clarify how aging of steel andstainless steel bolting would be managed in the absence of a Bolting Integrity Program. In a letter dated July 6, 2006, the applicant committed (Commitment #34) to prepare and submit an AMP consistent with GALL AMP XI.M18, "Bolting Integrity," for approval. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staff's evaluation of this program is documented in SER Section 3.0.3.2.19, which the staff found acceptable. With this AMP, the staff finds that the applicant's management of low alloy steel bolting will be consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant, with the Commitment #34 identifiedabove, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.1.2.1.15  Loss of Fracture Toughness Due to Thermal Aging Embrittlement In the discussion column of LRA Table 3.1.1, Item 3.1.1-55, the applicant stated that the InserviceInspection Program and the One-Time Inspection Program will be used to manage the reduction of fracture toughness in CASS components of the RCPB.The staff reviewed the applicant's Inservice Inspection Program and One-Time InspectionProgram. These evaluations are documented in SER Sections 3.0.3.3.3 and 3.0.3.1.6, respectively. The staff found each program acceptable. The applicant's management of loss of fracture toughness due to thermal aging embrittlement ofCASS pump casings and valve bodies 4 inches NPS and larger with the Inservice Inspection Program and the One-Time Inspection Program is consistent with the GALL Report and therefore acceptable to the staff. The use of the applicant's Inservice Inspection Program and One-Time Inspection Program for managing loss of fracture toughness of CASS valve bodies less than 4 inches NPS is appropriate because the adequacy of ISI has been demonstrated by NRC-performed bounding integrity analysis.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.1.2.1.16  Loss of Fracture Toughness Due to Thermal Aging Embrittlement In the discussion column of LRA Table 3.1.1, Item 3.1.1-57, the applicant stated that theOne-Time Inspection Program will be used to manage aging of the CASS main steam flow restrictors. VYNPS has no other Class 1 piping, piping components, piping elements, or CRDhousings made of CASS.During the audit and review, the applicant clarified the location and method of attachment of thiscomponent, which is welded to the inner surface of the main steam piping upstream of the main steam isolation valves (MSIVs).
3-180The staff finds that the CASS flow restrictor is not within the scope of GALL AMP XI.M12,"Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)," because it is neither a pressure-retaining component nor internal to the reactor vessel. In addition, the staff finds that the applicant's One-Time Inspection Program provides an appropriate way to confirm that no AERM affects the flow restrictor.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the associated aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed consistent with the AMRs in the GALL Report. Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is RecommendedIn LRA Section 3.1.2.2, the applicant further evaluates aging management, as recommended bythe GALL Report, for the reactor vessel, reactor vessel internals, and reactor coolant system components and provides information concerning how it will manage the following aging effects:
* cumulative fatigue damage
* loss of material due to general, pitting, and crevice corrosion
* loss of fracture toughness due to neutron irradiation embrittlement
* cracking due to stress corrosion cracking and intergranular stress-corrosion cracking
* crack growth due to cyclic loading
* loss of fracture toughness due to neutron irradiation embrittlement and void swelling
* cracking due to stress corrosion cracking
* cracking due to cyclic loading
* loss of preload due to stress relaxation
* loss of material due to erosion
* cracking due to flow-induced vibration
* cracking due to stress corrosion cracking and irradiation-assisted stress corrosioncracking
* cracking due to primary water stress corrosion cracking
* wall thinning due to flow-accelerated corrosion
* changes in dimensions due to void swelling 3-181
* cracking due to stress corrosion cracking and primary water stress corrosion cracking
* cracking due to stress corrosion cracking, primary water stress corrosion cracking, andirradiation-assisted stress corrosion cracking
* quality assurance for aging management of nonsafety-related componentsFor component groups evaluated in the GALL Report, for which the applicant claimedconsistency with the report and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations against the criteria contained in SRP-LR Appendix 3.1.2.2. The staff's review of theapplicant's further evaluation follows.3.1.2.2.1  Cumulative Fatigue Damage LRA Section 3.1.2.2.1 states that fatigue is a TLAA, as required by 10 CFR 54.3. Applicants mustevaluate TLAAs in accordance with 10 CFR 54.21(c)(1). The staff's review of the applicant's evaluation of fatigue for the reactor vessel and the reactor vessel internals is discussed in SER Sections 4.3.1.1 and 4.3.1.2, respectively. The staff's review of the applicant's evaluation of fatigue for the Class 1 portions of the reactor coolant boundary piping and components, including those for interconnecting systems, is discussed in SER Section 4.3.1.3.3.1.2.2.2  Loss of Material Due to General, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.1.2.2.2 against the following SRP-LR Appendix 3.1.2.2.2criteria:  (1)LRA Section 3.1.2.2.2 addresses loss of material in steel components of the reactorpressure vessel exposed to reactor coolant due to general, pitting and crevice corrosion.SRP-LR Section 3.1.2.2.2 states that loss of material due to general, pitting, and crevicecorrosion may occur in the steel pressurized water reactor (PWR) steam generator shell assembly exposed to secondary FW and steam. Loss of material due to general, pitting, and crevice corrosion also may occur in the steel top head enclosure (without cladding) top head nozzles (vent, top head spray or reactor core isolation cooling (RCIC), and spare) exposed to reactor coolant. The existing program controls reactor water chemistry to mitigate corrosion. However, control of water chemistry does not preclude loss of material due to pitting and crevice corrosion at locations with stagnant flow conditions; therefore, the effectiveness of water chemistry control programs should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to verify the effectiveness of water chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the component's intended functions will be maintained during the period of extended operation.
3-182LRA Section 3.1.2.2.2 states that loss of material due to general, pitting, and crevicecorrosion in steel components of the reactor pressure vessel exposed to reactor coolant is managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program through an inspection of a representative sample of components crediting this program including areas of stagnant flow. The Inservice Inspection Program supplements the Water Chemistry Control-BWR Program for these components.The staff finds that this meets the criteria of SRP-LR Section 3.1.2.2.2 and is thereforeacceptable.    (2)LRA Section 3.1.2.2.2 addresses loss of material in other steel components within theRCPB exposed to reactor coolant due to general, pitting, and crevice corrosion. SRP-LR Section 3.1.2.2.2 states that loss of material due to pitting and crevice corrosionmay occur in stainless steel BWR isolation condenser components exposed to reactor coolant. Loss of material due to general, pitting, and crevice corrosion may occur in steel BWR isolation condenser components. The existing program controls reactor water chemistry to mitigate corrosion. However, control of water chemistry does not preclude loss of material due to pitting and crevice corrosion at locations with stagnant flow conditions; therefore, the effectiveness of water chemistry control programs should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to verify the effectiveness of water chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the component's intended functions will be maintained during the period of extended operation.LRA Section 3.1.2.2.2 stated that this paragraph in the SRP-LR pertains to BWR isolationcondenser components. VYNPS does not have an isolation condenser, however, loss of material due to general, pitting, and crevice corrosion in other steel components within the RCPB exposed to reactor coolant is managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program through an inspection of a representative sample of components crediting this program including areas of stagnant flow. For some components, the Inservice Inspection Program supplements the Water Chemistry Control-BWR Program.The staff finds that this meets the criteria of SRP-LR Section 3.1.2.2.2 and is thereforeacceptable.  (3)LRA Section 3.1.2.2.2 addresses loss of material of stainless steel, nickel alloy, and steelwith stainless steel or nickel alloy cladding flanges, nozzles, penetrations, pressurehousings, safe ends, and vessel shells, heads and welds exposed to reactor coolant due to pitting and crevice corrosion.
3-183SRP-LR Section 3.1.2.2.2 states that loss of material due to pitting and crevice corrosionmay occur in stainless steel, nickel alloy, and steel with stainless steel or nickel alloycladding flanges, nozzles, penetrations, pressure housings, safe ends, and vessel shells, heads, and welds exposed to reactor coolant. The existing program controls reactor water chemistry to mitigate corrosion. However, control of water chemistry does not preclude loss of material due to pitting and crevice corrosion at locations with stagnant flow conditions; therefore, the effectiveness of water chemistry control programs should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to verify the effectiveness of water chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the component's intended functions will be maintained during the period of extended operation.LRA Section 3.1.2.2.2 stated that loss of material due to general, pitting, and crevicecorrosion in stainless steel, nickel-alloy and steel with stainless steel cladding componentsof the reactor pressure vessel, and loss of material in stainless steel (including CASS) components of the RCPB exposed to reactor coolant is managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program through an inspection of a representative sample of components crediting this program including areas of stagnant flow. The One-Time Inspection Program is also used to manage loss of material from the main steam flow restrictor by means of a component-specific inspection. For some components, the Inservice Inspection or the BWR Vessel Internals Program supplements the Water Chemistry Control-BWR Program.The staff finds that this meets the criteria of SRP-LR Section 3.1.2.2.2 and is thereforeacceptable.  (4)LRA Section 3.1.2.2.2 addresses that this paragraph in the SRP-LR applies to PWRsonly.SRP-LR Section 3.1.2.2.2 states that loss of material due to general, pitting, and crevicecorrosion may occur in the steel PWR steam generator upper and lower shell and transition cone exposed to secondary FW and steam. The existing program controls chemistry to mitigate corrosion and ISI to detect loss of material. The extent and schedule of the existing steam generator inspections are designed to ensure that flaws cannot attain a depth sufficient to threaten the integrity of the welds; however, in accordance with IN 90-04, the program may not be sufficient to detect pitting and crevice corrosion, if general and pitting corrosion of the shell is known to occur. The GALL Report recommends augmented inspection to manage this aging effect. Furthermore, the GALL Report clarifies that this issue is limited to Westinghouse Model 44 and 51 steam generators with a high-stress region at the shell to transition cone weld.Because VYNPS is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.2 doesnot apply to VYNPS.
3-184Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.1.2.2.2 criteria. For those line items that apply to LRA Section 3.1.2.2.2, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.2.3  Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement The staff reviewed LRA Section 3.1.2.2.3 against the following SRP-LR Section 3.1.2.2.3 criteria:
  (1)LRA Section 3.1.2.2.3 states that neutron irradiation embrittlement is a TLAA, as requiredby 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1).
SER Section 4.2 documents the staff's review of the applicant's evaluation of loss of fracture toughness for the reactor vessel beltline shell and welds.  (2)LRA Section 3.1.2.2.3 was reviewed by the staff and is addressed in SER Section 4.2.
Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.1.2.2.3 criteria. For those line items that apply to LRA Section 3.1.2.2.3, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.2.4  Cracking Due to Stress Corrosion Cracking and Intergranular Stress CorrosionCrackingThe staff reviewed LRA Section 3.1.2.2.4 against the following SRP-LR Section 3.1.2.2.4 criteria:
  (1)LRA Section 3.1.2.2.4 the applicant addresses cracking of stainless steel and nickel alloyBWR top head enclosure vessel flange leak detection lines due to SCC and IGSCC.SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in thestainless steel and nickel alloy BWR top head enclosure vessel flange leak detection lines. The GALL Report recommends that a plant-specific AMP be evaluated because existing programs may not be capable of mitigating or detecting cracking due to SCC and IGSCC.LRA Section 3.1.2.2.4 states that the Water Chemistry Control-BWR Program and theOne-Time Inspection Program will manage cracking due to SCC and IGSCC in the stainless steel head seal leak detection lines. The One-Time Inspection Program will include a volumetric examination for the detection of cracking.The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-TimeInspection Program and its evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable.
3-185The use of the One-Time Inspection Program in conjunction with the Water ChemistryControl-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. The staff finds that this combination satisfies the criteria of SRP-LR Appendix A.1 and is therefore acceptable.
  (2)LRA Section 3.1.2.2.4 states that VYNPS does not have an isolation condenser.SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur instainless steel BWR isolation condenser components exposed to reactor coolant. The existing program controls reactor water chemistry to mitigate SCC and relies on ASME Code, Section XI, ISI; however, the existing program should be augmented to detect cracking due to SCC and IGSCC. The GALL Report recommends an augmented program to include temperature and radioactivity monitoring of the shell-side water and eddy current testing of tubes to ensure that component intended functions will be maintained during the period of extended operation.Because VYNPS has no isolation condenser, the staff finds that this item of SRP-LRSection 3.1.2.2.4 does not apply to VYNPS.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.1.2.2.4 criteria. For those line items that apply to LRA Section 3.1.2.2.4, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.2.5  Crack Growth Due to Cyclic Loading LRA Section 3.1.2.2.5 states that further evaluation of aging management in this area is notapplicable to BWRs.The staff reviewed LRA Section 3.1.2.2.5 against the criteria in SRP-LR Section 3.1.2.2.5.
In LRA Section 3.1.2.2.5, the applicant stated that SRP-LR Section 3.1.2.2.5 applies to PWRsonly.SRP-LR Section 3.1.2.2.5 stated that crack growth due to cyclic loading could occur in reactorvessel shell forgings clad with stainless steel using a high-heat-input welding process. Growth of intergranular separations (underclad cracks) in the heat affected zone under austenitic stainless steel cladding is a TLAA to be evaluated for the period of extended operation for all the SA 508-Cl 2 forgings where the cladding was deposited with a high heat input welding process.The staff confirmed that the VYNPS vessel shell forgings were not clad using a high-heat-inputwelding process.On the basis that VYNPS does not have any components subject to this aging effect, the stafffinds that this aging effect does not require management at VYNPS.
3-1863.1.2.2.6  Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and VoidSwellingThe staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6.
In LRA Section 3.1.2.2.6, the applicant stated that SRP-LR Section 3.1.2.2.6 applies to PWRsonly.SRP-LR Section 3.1.2.2.6 states that loss of fracture toughness due to neutron irradiationembrittlement and void swelling may occur in stainless steel and nickel alloy reactor vessel internals components exposed to reactor coolant and neutron flux. The GALL Report recommends no further AMR if the applicant commits in the FSAR supplement: (1) to participate in industry programs for investigating and managing aging effects on reactor internals; (2) to evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, to submit an inspection plan for reactor internals to the staff for review and approval.The staff confirmed that the SRP-LR considers this aging effect/mechanism only for PWRcomponents.On the basis that VYNPS does not have any components subject to this aging effect, the stafffinds that this aging effect does not require management at VYNPS.
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.6 criteria. For those line items that apply to LRA Section 3.1.2.2.6, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.2.7  Cracking Due to Stress Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.7 against the following SRP-LR Section 3.1.2.2.7 criteria:
  (1)In LRA Section 3.1.2.2.7, the applicant stated that SRP-LR Section 3.1.2.2.7 applies toPWRs only.SRP-LR Section 3.1.2.2.7 states that cracking due to SCC may occur in the PWRstainless steel reactor vessel flange leak detection lines and bottom-mounted instrument guide tubes exposed to reactor coolant as well as in Class 1 PWR CASS reactor coolant system piping, piping components, and pipping elements exposed to reactor coolant. TheGALL Report recommends that a plant-specific AMP be evaluated to ensure that this aging effect is adequately managed.The staff confirmed that the SRP-LR considers this aging effect/mechanism only for PWRcomponents.
3-187On the basis that VYNPS does not have any components subject to this aging effect, the stafffinds that this aging effect does not require management at VYNPS.
 
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.7 criteria. For those line items that apply to LRA Section 3.1.2.2.7, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.2.8  Cracking Due to Cyclic Loading The staff reviewed LRA Section 3.1.2.2.8 against the following SRP-LR Section 3.1.2.2.8 criteria:
  (1)LRA Section 3.1.2.2.8 addresses cracking of stainless steel BWR jet pump sensing linesdue to cyclic loading.SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in thestainless steel BWR jet pump sensing lines. The GALL Report recommends that a plant-specific AMP be evaluated to ensure that this aging effect is adequately managed.LRA Section 3.1.2.2.8 stated that this paragraph in the SRP-LR pertains to the jet pumpsensing lines inside the reactor vessel. At VYNPS, these lines have no license renewal intended function and thus are not subject to an AMR.In addition, the LRA stated that the lines inside the vessel do not form part of the RCSpressure boundary and their failure would not affect the performance of any functions in the scope of license renewal. However, the lines outside the vessel are part of the RCS pressure boundary and are subject to an AMR. The staff's evaluation of these lines which are included as piping and fitting components less 4 inches NPS and managed using LRA Table 3.1-1, Item 3.1.1-48 is documented in SER Section 3.1.2.1.11.The staff finds that the applicant has demonstrated that the effects of aging will beadequately managed so that the intended functions will be maintained during the period of extended operation, as required by 10 CFR 54.21(a)(3).  (2)LRA Section 3.1.2.2.8 addresses the applicant stated that this paragraph in the SRP-LRpertains to BWR isolation condenser components. In LRA Section 3.1.2.2.8, the applicant stated that VYNPS does not have an isolation condenser.SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in steel andstainless steel BWR isolation condenser components exposed to reactor coolant. The existing program relies on ASME Code, Section XI, ISI; however, the existing program should be augmented to detect cracking due to cyclic loading. The GALL Report recommends an augmented program to include temperature and radioactivity monitoring of the shell-side water and eddy current testing of tubes to ensure that component intended functions will be maintained during the period of extended operation.
3-188Because VYNPS has no isolation condenser, the staff finds that this item in SRP-LRSection 3.1.2.2.8 does not apply to VYNPS.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.1.2.2.8 criteria. For those line items that apply to LRA Section 3.1.2.2.8, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.2.9  Loss of Preload Due to Stress Relaxation The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP-LR Section 3.1.2.2.9.
In LRA Section 3.1.2.2.9, the applicant stated that this paragraph in the SRP-LR applies to PWRsonly.SRP-LR Section 3.1.2.2.9 states that loss of preload due to stress relaxation may occur instainless steel and nickel alloy PWR reactor vessel internals screws, bolts, tie rods, and hold-down springs exposed to reactor coolant. The GALL Report recommends no further AMR if the applicant commits in the FSAR supplement: (1) to participate in the industry programs for investigating and managing aging effects on reactor internals; (2) to evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, to submit an inspection plan for reactor internals to the staff for review and approval.On the basis that VYNPS does not have any components subject to this aging effect, the stafffinds that this aging effect does not require management at VYNPS.3.1.2.2.10  Loss of Material Due to Erosion The staff reviewed LRA Section 3.1.2.2.10 against the criteria in SRP-LR Section 3.1.2.2.10.
In LRA Section 3.1.2.2.10, the applicant stated that this paragraph in the SRP-LR applies toPWRs only.SRP-LR Section 3.1.2.2.10 states that loss of material due to erosion may occur in steel steamgenerator FW impingement plates and supports exposed to secondary FW. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that this aging effect is adequately managed.On the basis that VYNPS does not have any components subject to this aging effect, the stafffinds that this aging effect does not require management at VYNPS.
3-1893.1.2.2.11  Cracking Due to Flow-Induced VibrationThe staff reviewed LRA Section 3.1.2.2.11 against the criteria in SRP-LR Section 3.1.2.2.11.
LRA Section 3.1.2.2.11 addresses cracking of stainless steel steam dryers due to flow-inducedvibration.SRP-LR Section 3.1.2.2.11 states that loss of material due to erosion may occur in steel steamgenerator FW impingement plates and supports exposed to secondary FW. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that this aging effect is adequately managed.The staff, as part of the its review of the applicant's extended power uprate (EPU) application,conducted extensive reviews of the steam dryers. The staff reviewed the steam dryer analysis, and conducted technical audits at the GE Scale Model Test facility near San Jose, California and the GE office in Washington, DC. The steam dryer analysis involved evaluation of the pressure loads acting on the steam dryer during operation using computational fluid dynamics and acoustic circuit model analyses. The staff found that the uncertainty assumed by the applicant in its determination of the loads from the computational fluid dynamics analysis was significantlyunderestimated. To address this concern, and to confirm the applicant's predictions regarding the hydrodynamic and acoustic loads on the steam dryer, the staff added license conditions to the VYNPS Facility Operation License when it approved the EPU in March 2006. The license conditions require monitoring, evaluating, and taking prompt action in response to potential adverse flow effects as a result of operation under extended power uprate conditions. One license condition also specifies visual inspections of the steam dryers during three consecutiverefueling outages beginning with the spring 2007 refueling outage.The staff reviewed plant experience at Hatch and Brunswick related to plant transients afterextended power uprates and did not observe any abnormal behavior in the steam dryers. On the basis of the operating experience and license conditions, the staff concludes that there is reasonable assurance that the VYNPS steam dryers will perform satisfactorily inservice under extended power uprate conditions during the proposed renewal period provided an adequate aging management program is used.The applicant stated that cracking due to flow-induced vibration in the stainless steel steamdryers is managed by the BWR Vessel Internals Program. The BWR Vessel Internals Program currently incorporates the guidance of GE-SIL-644, Revision 1. VYNPS will evaluate BWRVIP-139 once it is approved by the staff and either include its recommendations in the VYNPS BWR Vessel Internals Program or inform the staff of VYNPS's exceptions to that document.The staff finds the applicant's approach for managing cracking of steam dryers due toflow-induced vibration to be acceptable because the approach will be based on the guidelines developed by the ongoing activity of the BWRVIP. In addition, in a letter dated August 22, 2006, the applicant committed (Commitment #37) to continue inspections in accordance with the steam dryer monitoring plan, Revision 3, in the event that BWRVIP-139 is not approved prior to the period of extended operation.
3-190The staff finds that since the applicant has committed (Commiment #37) to implementBWRVIP-139 as approved by the staff, if the staff does approve BWRVIP-139, this aging effect/mechanism will be adequately managed as recommended by the GALL Report. If the staff does not issue an SER approving the use of BWRVIP-139, the applicant must submit, for review and approval, a plant-specific program to manage cracking of the steam dryers due to flow-induced vibration. This must occur at least 24 months prior to the period of extended operation.The staff reviewed the applicant's BWR Vessel Internals Program and finds it to be an acceptablemethod for managing cracking of the steam dryers due to flow-induced vibration based upon a commitment to implement BWRVIP-139 or to provide a plant-specific program for management of cracking in the steam dryers to the NRC for review and approval prior to the period of extended operation.Based on the programs identified above and Commitment #37, the staff concludes that theapplicant's programs meet SRP-LR Section 3.1.2.2.11 criteria. For those line items that apply to LRA Section 3.1.2.2.11, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.2.12  Cracking Due to Stress Corrosion Cracking and Irradiation-Assisted Stress CorrosionCrackingThe staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP-LR Section 3.1.2.2.12.
In LRA Section 3.1.2.2.12, the applicant stated that this paragraph in the SRP-LR applies toPWRs only.SRP-LR Section 3.1.2.2.12 states that cracking due to SCC and IASCC may occur in PWRstainless steel reactor internals exposed to reactor coolant. The existing program controls water chemistry to mitigate these aging effects. The GALL Report recommends no further AMR if the applicant commits in the FSAR supplement: (1) to participate in the industry programs for investigating and managing aging effects on reactor internals; (2) to evaluate and implement the results of the industry programs as applicable to the reactor internals;, and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, to submit an inspection plan for reactor internals to the staff for review and approval.On the basis that VYNPS does not have any components subject to this aging effect, the stafffinds that this aging effect does not require management at VYNPS.
3-1913.1.2.2.13  Cracking Due to Primary Water Stress Corrosion CrackingThe staff reviewed LRA Section 3.1.2.2.13 against the criteria in SRP-LR Section 3.1.2.2.13.
In LRA Section 3.1.2.2.13, the applicant stated that this paragraph in the SRP-LR applies toPWRs only.SRP-LR Section 3.1.2.2.13 states that cracking due to primary water stress corrosion cracking(PWSCC) may occur in PWR components made of nickel alloy and steel with nickel alloy cladding, including RCPB components and penetrations inside the reactor coolant system suchas pressurizer heater sheathes and sleeves, nozzles, and other internal components. Except for reactor vessel upper head nozzles and penetrations, the GALL Report recommends ASME Code, Section XI, ISI (for Class 1 components) and control of water chemistry. For nickel alloy components, no further AMR is necessary if the applicant complies with applicable NRC orders and commits in the FSAR supplement to implement applicable: (1) bulletins and GLs; and (2) staff-accepted industry guidelines.On the basis that VYNPS does not have any components subject to this aging effect, the stafffinds that this aging effect does not require management at VYNPS.3.1.2.2.14  Wall Thinning Due to Flow-Accelerated Corrosion The staff reviewed LRA Section 3.1.2.2.14 against the criteria in SRP-LR Section 3.1.2.2.14.
In LRA Section 3.1.2.2.14, the applicant stated that this paragraph in the SRP-LR applies toPWRs only.SRP-LR Section 3.1.2.2.14 states that wall thinning due to flow-accelerated corrosion may occurin steel FW inlet rings and supports. The GALL Report references IN 91-19, ?Steam GeneratorFeedwater Distribution Piping Damage," for evidence of flow-accelerated corrosion in steam generators and recommends that a plant-specific AMP be evaluated because existing programs may not be capable of mitigating or detecting wall thinning due to flow-accelerated corrosion.On the basis that VYNPS does not have any components subject to this aging effect, the stafffinds that this aging effect does not require management at VYNPS3.1.2.2.15  Changes in Dimensions Due to Void Swelling The staff reviewed LRA Section 3.1.2.2.15 against the criteria in SRP-LR Section 3.1.2.2.15.
In LRA Section 3.1.2.2.15, the applicant stated that this paragraph in the SRP-LR applies toPWRs only.SRP-LR Section 3.1.2.2.15 states that changes in dimensions due to void swelling may occur instainless steel and nickel alloy PWR internal components exposed to reactor coolant. The GALL Report recommends no further AMR if the applicant commits in the FSAR supplement: (1) to participate in the industry programs for investigating and managing aging effects on reactor internals; (2) to evaluate and implement the results of the industry programs as applicable to the 3-192reactor internals; and (3) upon completion of these programs, but not less than 24 months beforeentering the period of extended operation, to submit an inspection plan for reactor internals to the staff for review and approval.On the basis that VYNPS does not have any components subject to this aging effect, the stafffinds that this aging effect does not require management at VYNPS.3.1.2.2.16  Cracking Due to Stress Corrosion Cracking and Primary Water Stress CorrosionCrackingThe staff reviewed LRA Section 3.1.2.2.16 against the following SRP-LR Section 3.1.2.2.16criteria:In LRA Section 3.1.2.2.16, the applicant stated that this paragraph in the SRP-LR applies toPWRs only.SRP-LR Section 3.1.2.2.16 states that cracking due to SCC may occur on the primary coolantside of PWR steel steam generator upper and lower heads, tubesheets, and tube-to-tube sheet welds made or clad with stainless steel. Cracking due to PWSCC may occur on the primary coolant side of PWR steel steam generator upper and lower heads, tubesheets, and tube-to-tube sheet welds made or clad with nickel alloy. Cracking due to SCC could occur on stainless steel pressurizer spray heads; and cracking due to PWSCC could occur on nickel-alloy pressurizer spray heads. The GALL Report recommends ASME Code, Section XI, ISI and control of water chemistry to manage this aging effect and recommends no further AMR for PWSCC of nickel alloy if the applicant complies with applicable NRC orders and commits in the FSAR supplement to implement applicable: (1) bulletins and GLs; and (2) staff-accepted industry guidelines.On the basis that VYNPS does not have any components subject to this aging effect, the stafffinds that this aging effect does not require management at VYNPS.
3.1.2.2.17  Cracking Due to Stress Corrosion Cracking, Primary Water Stress Corrosion Cracking, and Irradiation-Assisted Stress Corrosion CrackingThe staff reviewed LRA Section 3.1.2.2.17 against the criteria in SRP-LR Section 3.1.2.2.17.
In LRA Section 3.1.2.2.17, the applicant stated that this paragraph in the SRP-LR applies toPWRs only.SRP-LR Section 3.1.2.2.17 states that cracking due to SCC, PWSCC, and IASCC may occur inPWR stainless steel and nickel alloy reactor vessel internals components. The existing program controls water chemistry to mitigate these aging effects; however, the existing program should be augmented to manage these aging effects for reactor vessel internals components. The GALL Report recommends no further AMR if the applicant commits in the FSAR supplement: (1) to participate in the industry programs for investigating and managing aging effects on reactor internals; (2) to evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, to submit an inspection plan for reactor internals to the staff for review and approval.
3-193On the basis that VYNPS does not have any components subject to this aging effect, the stafffinds that this aging effect does not require management at VYNPS.3.1.2.2.18  Quality Assurance for Aging Management of Nonsafety-Related Components SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program, which thestaff found acceptable.
Conclusion. On the basis of its review, for applicable component groups evaluated in the GALLReport for which the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determines that the applicant adequately addressed the issues that were further evaluated. The staff finds that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.3  AMR Results Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.1.2-1 through 3.1.2-3, thestaff reviewed additional details of the AMR results for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report.In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant indicated, via notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information about how it will manage the aging effects. Specifically, note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.Staff Evaluation. For component type, material, and environment combinations not evaluated inthe GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff's evaluation is documented in the following sections.3.1.2.3.1  Reactor Vessel Summary of Aging Management Evaluation - LRA Table 3.1.2-1 The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for thereactor vessel component groups.In LRA Table 3.1.2-1, the applicant proposed to manage loss of material from low-alloy steelclosure flange studs, nuts, washers and bushings exposed to air using AMP B.1.23, "Reactor Head Closure Studs Program."
3-194The staff reviewed the Reactor Head Closure Studs Program and its evaluation is documented inSER Section 3.0.3.2.14. The program includes ISI in conformance with the requirements of ASME Code, Section XI, Subsection IWB, and preventive measures to mitigate cracking and loss of material of reactor head closure studs, nuts, washers, and bushings. The staff determines that the AMP is adequate for managing the aging effects for which it is credited. On the basis of its review, the staff finds the aging effect of loss of material from low-alloy steel closure flange studs, nuts, washers and bushings exposed to air is effectively managed using the Reactor Head Closure Studs Program.In LRA Table 3.1.2-1, the applicant proposed to manage loss of material from low-alloy steelstabilizer pads and support skirt exposed to air using the Inservice Inspection (ISI) Program.The staff reviewed the Inservice Inspection Program and its evaluation is documented in SERSection 3.0.3.3.3, which the staff found acceptable. The plant-specific program implements ISI in conformance with the requirements of ASME Code, Section XI and 10 CFR 50.55a. The staff determines that the AMP is adequate for managing the aging effects for which it is credited. On the basis of its review, the staff finds the aging effect of loss of material from low-alloy steel stabilizer pads and support skirt exposed to air is effectively managed using the Inservice Inspection Program.In LRA Table 3.1.2-1, the applicant proposed to manage cracking of the stainless steel cap onthe CRD return line exposed to treated water greater than 270F using the BWR CRD ReturnLine Nozzle Program and the Water Chemistry Control - BWR Program. The staff reviewed the BWR CRD Return Line Nozzle Program and the Water Chemistry Control - BWR Program.
These evaluations are documented in SER Sections 3.0.3.2.2 and 3.0.3.1.11, respectively. The staff found each program acceptable.The applicant stated that it has rerouted the CRD return flow to the reactor water cleanup(RWCU) system and capped the CRD return line vessel nozzle to mitigate cracking. The applicant further stated that it will monitor the effects of crack initiation and growth on the intended function of the control rod drive return line nozzle and cap by implementing AMP B.1.2, "BWR CRD Return Line Nozzle." AMP B.1.2 complies with the requirements of GALL AMP XI.M6, "BWR CRD Return Line Nozzle," with one exception. The staff reviewed this exception and to determine the validity of the applicant's technical basis to exclude the weld joint between CRD return line and the RWCU piping from the aging management review. GALL AMP XI.M6 requires application of the American Society of Mechanical Engineers (ASME) Code Section XI, 2001 Edition through 2003 Addenda, Subsection IWB 2500-1 inspection requirements, and the NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking,"
recommendations to monitor this aging effect in the CRD return line welds.
 
3-195With respect to the aging degradation of the capped CRD return line nozzle, the applicant statedthat the capped CRD return line nozzle at the VYNPS unit will be monitored by the ASME Code, Section XI inservice inspection (ISI) examination as required by AMP B.1.2. In RAI B.1.2-1, dated August 16, 2006, the staff requested that the applicant provide the following information regarding the CRD return line capped weld:(1) Configuration, location and material of construction of the capped nozzle. This should include the existing base material for the nozzle, piping (if piping remnants exist) and cap material, and any welds.(2) Inspection criteria for this weld and the cap are managed in accordance with the guidelines of BWRVIP-75, "BWR Vessel and Internals Project (BWRVIP), Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedule." (3) The effect of the event at Pilgrim (leaking weld at capped nozzle, September 30, 2003) is applicable to VYNPS. The staff issued Information Notice 2004-08, "Reactor Coolant Pressure Boundary Leakage Attributable to Propagation of Cracking in Reactor Vessel Nozzle Welds,"
dated April 22, 2004, which states that the cracking occurred in an Alloy 182 weld that was previously repaired extensively. Discuss experience with previous leakage at the VYNPS capped nozzle, if any.
Include in your discussion the past inspection techniques applied, the results obtained, and mitigative strategies imposed. Provide information as to how the plant-specific experience related to this aging effect impacts the attributes specified in AMP B.1.2, "BWR CRD Return line Nozzles."In response to RAI B.1.2-1, in a letter dated August 30, 2006, the applicant stated that thematerial of construction of the cap at the VYNPS unit is ASME SA 182 Grade 316 L (low carbon) stainless steel. Type 316L (low carbon) stainless steel weld material, which has better resistanceto IGSCC than non-L grade stainless steel weld material, was used for the cap-to-nozzle weld. At the time of installation (1979) visual testing (VT), liquid penetrant testing (PT), and radiographic testing (RT) were performed on the cap-to-nozzle weld and no reportable indications were found.
Subsequent examinations included ultrasonic testing (UT) and VT in 1979, PT in 1989, and UT and PT in 2002, and thus far no reportable indications were identified.
The applicant stated that by using a low carbon stainless steel base metal cap and low carbon stainless steel weld material, it can mitigate IGSCC in the cap-to-nozzle weld. Since past inspections indicated no active aging degradation in the cap-to-nozzle weld, the applicant concluded that the aging degradation in the subject weld is adequately managed by the BWR CRD Return Line Nozzle Program.The staff reviewed the applicant's response and finds it acceptable because implementation ofthe BWR CRD Return Line Nozzle Program and the inspection requirements of the ASME Code, Section XI ISI Program for the CRD return lines would be consistent with the GALL AMP XI.M6.
The staff's concern described in RAI B.1.2-1 is resolved. On the basis of its review, the staff finds the aging effect of cracking of the stainless steel CRD return line cap is effectively managed using the BWR CRD Return Line Nozzle Program and the Water Chemistry Control - BWR Program.
3-196In LRA Table 3.1.2-1, the applicant proposed to manage cracking of the low-alloy steel bottomhead, upper head, closure flanges, shell, main steam nozzle, and drain nozzle exposed to treated water greater than 220F using the Inservice Inspection (ISI) Program and the Water ChemistryControl - BWR Program.The staff reviewed the Inservice Inspection Program and the Water Chemistry Control - BWRProgram. These evaluations are documented in SER Sections 3.0.3.3.3 and 3.0.3.1.11, respectively. The Water Chemistry Control - BWR Program mitigates cracking of low-alloy steel components fully or partially clad with stainless steel in contact with reactor coolant. The Inservice Inspection Program monitors the effects of crack initiation and growth on the intended function of bottom head, upper head, closure flanges, shell, main steam nozzle, and drain nozzle. The staff determines that these programs are adequate to manage the aging effects for which they are credited. On the basis of its review the staff finds the aging effect of cracking of the low-alloy steel bottom head, upper head, closure flanges, shell, main steam nozzle, and drain nozzle is effectively managed using the Inservice Inspection Program and the Water Chemistry Control -
BWR Program.In LRA Table 3.1.2-1, the applicant proposed to manage fatigue damage (cracking-fatigue) of thestainless steel bolting for flanges and incore housing exposed to air using a TLAA.During the audit and review, the staff noted that TLAA-metal fatigue was credited for managingcracking due to fatigue for almost all of the component types in the reactor coolant system. The applicant responded that entries listing cracking fatigue with TLAA-metal fatigue only met the screening criteria and these entries must be reviewed to determine if a TLAA-metal fatigue analysis exists. In a letter dated July 14, 2006, the applicant revised the LRA by deleting the line item in LRA Table 3.1.2-1 for incore housing bolting in which cracking-fatigue was managed by TLAA-metal fatigue. The staff finds this acceptable. On the basis of its review, the staff finds cracking due to fatigue for incore housing bolting is not managed by TLAA-metal fatigue as previously stated in the LRA. Cracking is instead managed using the Inservice Inspection Program. The staff determines that this program is adequate to manage the aging effects for which it is credited.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.3.2  Reactor Vessel Internals Summary of Aging Management Evaluation - LRATable 3.1.2-2The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for thereactor vessel internals component groups.In LRA Table 3.1.2-2, the applicant proposed to manage loss of preload of stainless steel coreplate rim hold-down bolts exposed to treated water greater than 270F using a TLAA.
3-197The core plate rim hold-down bolts are subject to stress relaxation due to thermal and irradiationeffects and, consequently, they would experience 5 to 19 percent loss of preload. The applicant identified that loss of preload in core plate rim hold-down bolts is a TLAA issue. The applicant, in LRA Section 4.7.2.2, stated that it would comply with the guidelines specified in the Boiling Water Reactor Vessel Inspection Program BWRVIP-25 report, "BWR Core Plate Inspection and Flaw Evaluation Guidelines," which includes inspection criteria for the core plate rim hold-down bolts.
The applicant claimed that by invoking the inspection requirements of the BWRVIP-25 report it would adequately manage loss of preload of the core plate rim hold-down bolts during the extended period of operation.With respect to the TLAA issue associated with the loss of preload for the core plate rimhold-down bolts, the applicant stated that to date no plant-specific analysis was done in accordance with the current licensing basis. The applicant however, made a commitment (Commitment # 29) to either install wedges or perform plant-specific analysis that meets the requirements of the BWRVIP-25 report. If the applicant chooses to install wedges, the core plate rim hold-down bolts are excluded from the BWRVIP-25 inspection guidelines. The staff evaluation of this TLAA is documented in SER Section 4.7.
 
On the basis of its review, the staff finds that, with Commitment #29, the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.3.3  Reactor Coolant Pressure Boundary Summary of Aging Management Evaluation - LRATable 3.1.2-3The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for theRCPB component groups.In LRA Table 3.1.2-3, the applicant proposed to manage cracking of low-alloy and stainless steelbolting exposed to air using the Inservice Inspection Program.
The staff reviewed the Inservice Inspection Program and its evaluation is documented in SER Section 3.0.3.3.3. The staff asked the applicant to clarify how aging of stainless steel bolting would be adequately managed in the absence of a Bolting Integrity Program. In a letter dated July 6, 2006, the applicant agreed to prepare and submit an AMP consistent with GALL AMP XI.M18, "Bolting integrity," for approval. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staff's evaluation of this program is documented in SER Section 3.0.3.2.19. The staff finds that, with this AMP, the applicant's management of low-alloy and stainless steel bolting of the RCS pressure boundary is consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-1983.1.2.3.4  Aging Effect/Mechanism in Table 3.1.1 That are Not Applicable for VYNPSThe staff reviewed LRA Table 3.1.1, which provides a summary of aging managementevaluations for the reactor vessel, internals and reactor coolant system evaluated in the GALL Report.In LRA Table 3.1.1, Item 3.1.1-25, the applicant stated that the jet pump instrumentation linesinside the reactor vessel have no intended function within the scope of license renewal and for that reason are not subject to an AMR. The lines outside the vessel are part of the RCS pressure boundary and are subject to an AMR. These lines are included as piping and fittings less than 4 inches NPS. During the audit and review, the applicant confirmed that component types subject to this aging effect are addressed by LRA Table 3.1.1, Item 3.1.1-48. The evaluation of Table 3.1.1, Item 3.1.1-48 is documented in SER Section 3.1.2.1.11.In LRA Table 3.1.1, Item 3.1.1-46, the applicant stated that the cracking of nickel alloy coreshroud and core plate access hole cover (mechanical covers) due to SCC, IGSCC, and IASCC is not applicable at VYNPS. On the basis that the access hole covers are welded in a manner that leaves no crevice for which augmented inspection would be appropriate, the staff finds that, for this component type, this aging effect is not applicable to VYNPS.In LRA Table 3.1.1, Item 3.1.1-53, the applicant stated that the loss of material of steel piping,piping components, and piping elements exposed to closed cycle cooling water due to general,pitting and crevice corrosion is not applicable at VYNPS. On the basis that there are no components exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for these systems.In LRA Table 3.1.1, Item 3.1.1-54, the applicant stated that the loss of material of copper alloypiping, piping components, and piping elements exposed to closed cycle cooling water due topitting, crevice, and galvanic corrosion is not applicable at VYNPS. On the basis that there are no copper-alloy components in the reactor vessel, internals and reactor coolant system at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for these systems.In LRA Table 3.1.1, Item 3.1.1-56, the applicant stated that the loss of material of copperalloy greater than 15 percent zinc piping, piping components, and piping elements exposed to closed cycle cooling water due to selective leaching is not applicable at VYNPS. On the basis that there are no copper-alloy components in the reactor vessel, internals and reactor coolant system at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for these systems.3.1.2.3.5  Reactor Vessel, Internals and Reactor Coolant System AMR Line Items That Have NoAging Effects (LRA Tables 3.1.2-1 through 3.1.2-3)In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant identified line items where no aging effectswere identified as a result of its aging review process.
3-199In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant identified AMR line items where no agingeffects were identified as a result of its aging review process. Specifically, instances in which the applicant states that no aging effects were identified occurred when components fabricated from carbon and low-alloy steel are exposed to an (indoor) air environment.Industry experience has shown that general corrosion of carbon steel or low-alloy steelcomponents occurs only if the components were exposed to outdoor environments or to indoor environments that could promote the condensation of water on the external surfaces of the components. The external surface of the reactor vessel and the piping, fittings, and valve bodies of the reactor pressure boundary are normally at elevated temperatures. Consequently they are always dry, and corrosion is not observed.The staff acknowledged, in NUREG-1833, that steel in an indoor controlled air environmentexhibits no aging effect and that steel components and structures will therefore remain capable of performing intended functions consistent with the CLB for the period of extended operation.
Because the external surface of the reactor vessel and the piping, fittings, and valve bodies of the reactor pressure boundary are not subject to an AERM, the staff finds the absence of an AMP for these component types to be acceptable. The staff concludes that there are no AERMs for carbon and low-alloy steel components exposed to indoor air.On the basis of its review, the staff finds that the applicant appropriately evaluated the AMRresults involving material, environment, AERMs, and AMP combinations that are not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.3  ConclusionThe staff concludes that the applicant has provided sufficient information to demonstrate that theeffects of aging for the reactor vessel, reactor vessel internals, and reactor coolant system components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.2  Aging Management of Engineered Safety Features SystemsThis section of the SER documents the staff's review of the applicant's AMR results for the ESF systems components and component groups of:
* residual heat removal system
* core spray system
* automatic depressurization system
* high pressure coolant injection system
* reactor core isolation cooling system
* standby gas treatment system
* primary containment penetrations 3-2003.2.1  Summary of Technical Information in the ApplicationLRA Section 3.2 provides AMR results for the ESF systems components and component groups.LRA Table 3.2.1, "Summary of Aging Management Evaluations for the Engineered Safety Features," is a summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the ESF systems components and component groups.The applicant's AMRs evaluated and incorporated applicable plant-specific and industry operatingexperience in the determination of AERMs. The plant-specific evaluation included condition reports and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.3.2.2  Staff EvaluationThe staff reviewed LRA Section 3.2 to determine whether the applicant provided sufficientinformation to demonstrate that the effects of aging for the ESF systems components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRswere consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's audit evaluation are documented in SER Section 3.2.2.1.In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for whichfurther evaluation is recommended. The staff confirmed that the applicant's further evaluations were consistent with the SRP-LR Section 3.2.2.2 acceptance criteria. The staff's audit evaluations are documented in SER Section 3.2.2.2.The staff also conducted a technical review of the remaining AMRs that were not consistent with,or not addressed in, the GALL Report. The technical review evaluated whether all plausible aging effects have been identified and whether the aging effects listed were appropriate for the material-environment combinations specified. The staff's evaluations are documented in SER Section 3.2.2.3.For SSCs which the applicant claimed were not applicable or required no aging management, thestaff reviewed the AMR line items and the plant's operating experience to verify the applicant's
 
claims.Table 3.2-1 summarizes the staff's evaluation of components, aging effects/mechanisms, andAMPs listed in LRA Section 3.2 and addressed in the GALL Report.
3-201Table 3.2-1  Staff Evaluation for Engineered Safety Features Systems Components in theGALL ReportComponent Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation Steel and stainless steel piping, piping
 
components, and
 
piping elements in
 
ECCS (3.2.1-1)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAAFatigue is a TLAA.(See SER Section 4.3.1.3.2)Steel with stainless steel cladding pump casing exposed to
 
treated borated water (3.2.1-2)Loss of material due to cladding breach A plant-specificAMP is to be evaluated.Reference NRC Information Notice 94-63, "Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks"NoneNot applicable toBWRs Stainless steel containment
 
isolation piping and
 
components internal surfaces exposed to treated water
 
(3.2.1-3)Loss of material due to pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection
 
Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.2.2.2.3)
Stainless steel piping, piping
 
components, and
 
piping elements exposed to soil
 
(3.2.1-4)Loss of material due to pitting and crevice corrosion A plant-specificAMP is to be evaluated.NoneNot applicable (See SER Section 3.2.2.2.3)
Stainless steel and aluminum piping, piping components, and piping elements exposed to treated water (3.2.1-5)Loss of material due to pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.2.2.2.3)
Stainless steel andcopper alloy piping, piping components, and piping elements exposed to
 
lubricating oil
 
(3.2.1-6)Loss of material due to pitting and crevice corrosionLubricating OilAnalysis and One-Time InspectionOil Analysis Program (B.1.20);
One-Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.2.2.2.3)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-202Partially encased stainless steel tanks with breached moisture barrier exposed to raw water (3.2.1-7)Loss of material due to pitting and crevice corrosion A plant-specificAMP is to be evaluated for pitting and crevice
 
corrosion of tank
 
bottoms because moisture and water
 
can egress under
 
the tank due to
 
cracking of the
 
perimeter seal from weathering.NoneNot applicable (See SER Section 3.2.2.2.3)
Stainless steel piping, piping
 
components, piping
 
elements, and tank
 
internal surfaces exposed to
 
condensation (internal)
 
(3.2.1-8)Loss of material due to pitting and crevice corrosion A plant-specificAMP is to be evaluated.
PeriodicSurveillance and Preventive Maintenance
 
Program (B.1.22)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.2.2.2.3)
Steel, stainless steel, and copper alloy heat exchanger tubes exposed to
 
lubricating oil
 
(3.2.1-9)Reduction of heat transfer due to
 
foulingLubricating OilAnalysis and One-Time InspectionOil Analysis Program (B.1.20);
One-Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.2.2.2.4)
Stainless steel heatexchanger tubes exposed to treated water (3.2.1-10)Reduction of heat transfer due to
 
foulingWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.2.2.2.4)
Elastomer seals and components in SGTS exposed to
 
air - indoor
 
uncontrolled
 
(3.2.1-11)Hardening and loss of strength due to
 
elastomer degradation A plant-specificAMP is to be evaluated.NoneNot applicable (See SER Section 3.2.2.2.5)
Stainless steel high-pressure safety
 
injection (charging)
 
pump miniflow orifice exposed to
 
treated borated water (3.2.1-12)
Loss of material due to erosion A plant-specificAMP is to be evaluated for
 
erosion of the orifice due to extended use
 
of the centrifugal
 
high pressure safety
 
injection pump for
 
normal charging.NoneNot applicable(PWR)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-203Steel drywell and suppression
 
chamber spray system nozzle and flow orifice internal surfaces exposed to
 
air - indoor
 
uncontrolled (internal)
 
(3.2.1-13)
Loss of material due to general corrosion
 
and fouling A plant-specificAMP is to be evaluated.NoneNot applicable (See SER Section 3.2.2.2.7)
Steel piping, piping components, and
 
piping elements exposed to treated water (3.2.1-14)
Loss of material due to general, pitting, and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One Time Inspection Program (B.1.21Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.2.2.2.8)
Steel containment isolation piping, piping components, and piping elements
 
internal surfaces exposed to treated water (3.2.1-15)
Loss of material due to general, pitting, and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.2.2.2.8)
Steel piping, piping components, and
 
piping elements exposed to
 
lubricating oil
 
(3.2.1-16)
Loss of material due to general, pitting, and crevice corrosionLubricating OilAnalysis and One-Time InspectionOil Analysis Program (B.1.20);
One-Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.2.2.2.8)Steel (with orwithout coating or wrapping) piping, piping components, and piping elements
 
buried in soil
 
(3.2.1-17)
Loss of material due to general, pitting, crevice, and MIC Buried Piping andTanks Surveillance
 
or Buried Piping and Tanks Inspection Buried Piping Inspection Program (B.1.1)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.2.2.2.9)
Stainless steel piping, piping
 
components, and
 
piping elements exposed to treated water > 60C (> 140F)(3.2.1-18)Cracking due toSCC and IGSCCBWR StressCorrosion Cracking and Water ChemistryBWR StressCorrosion Cracking
 
Program (B.1.5);
Water Chemistry Control-BWR
 
Program (B.1.30.2);
One-Time Inspection
 
Program (B.1.21)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1.9)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-204 Steel piping, piping components, and
 
piping elements exposed to steam or treated water
 
(3.2.1-19)Wall thinning due toflow-accelerated corrosionFlow-AcceleratedCorrosionFlow-AcceleratedCorrosion Program (B.1.13)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1.10)
CASS piping, piping components, and
 
piping elements exposed to treated water (borated or
 
unborated) > 250C (> 482F)(3.2.1-20)
Loss of fracture toughness due to
 
thermal aging
 
embrittlementThermal Aging Embrittlement of
 
CASSNoneNot applicable(There are no CASS
 
components in the ESF systems.)(See SER Section 3.2.2.3.8)High-strength steel closure bolting exposed to air with steam or water
 
leakage (3.2.1-21)Cracking due tocyclic loading, SCCBolting IntegrityNoneNot applicable(High strength steel
 
closure bolting is
 
not used in ESF systems.)
(See SER Section 3.2.2.3.8)
Steel closure boltingexposed to air with steam or water
 
leakage (3.2.1-22)
Loss of material due to general corrosionBolting IntegrityBolting Integrity Program (B.1.31)Consistent with theGALL Report.
(See SER Section 3.2.2.3.8)
Steel bolting and closure bolting exposed to air -
outdoor (external),
or air - indoor
 
uncontrolled (external)
 
(3.2.1-23)
Loss of material due to general, pitting, and crevice corrosionBolting IntegritySystem Walkdown Program (B.1.28) and
 
Bolting Integrity
 
Program (B.1.31) Consistent with theGALL Report.
(See SER Section 3.2.2.1.11)
Steel closure boltingexposed to air -
 
indoor uncontrolled (external)
 
(3.2.1-24)
Loss of preload due to thermal effects, gasket creep, and
 
self-looseningBolting IntegrityBolting Integrity Program (B.1.31)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1.18)
Stainless steel piping, piping
 
components, and
 
piping elements exposed to closed cycle cooling water
 
> 60C (> 140F)(3.2.1-25)Cracking due to SCCClosed-CycleCooling Water SystemWater ChemistryControl-Closed Cooling Water
 
Program (B.1.30.3)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-205 Steel piping, piping components, and
 
piping elements exposed to closed cycle cooling water
 
(3.2.1-26)
Loss of material due to general, pitting, and crevice corrosionClosed-CycleCooling Water SystemNoneNot applicable.(Steel containment
 
isolation components exposed to closed cycle cooling water
 
are all part of other safety systems that are evaluated separately.)
(See SER Section 3.2.2.3.8)
Steel heatexchanger components exposed to closed cycle cooling water
 
(3.2.1-27)
Loss of material due to general, pitting, crevice, and galvanic corrosionClosed-CycleCooling Water SystemWater ChemistryControl-Closed Cooling Water
 
Program (B.1.30.3)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1)
Stainless steel piping, piping
 
components, piping
 
elements, and heat exchanger components exposed to closed-cycle cooling water (3.2.1-28)
Loss of material due to pitting and crevice corrosionClosed-CycleCooling Water SystemWater ChemistryControl-Closed Cooling Water
 
Program (B.1.30.3)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1)Copper alloy piping, piping components, piping elements, and heat exchanger
 
components exposed to closed cycle cooling water
 
(3.2.1-29)
Loss of material dueto pitting, crevice, and galvanic corrosionClosed-CycleCooling Water SystemNoneThere are no copperalloy components exposed to closed cycle cooling water
 
in the ESF systems.)
(See SER Section 3.2.2.3.8)
Stainless steel andcopper alloy heat exchanger tubes exposed to closed cycle cooling water
 
(3.2.1-30)Reduction of heat transfer due to
 
foulingClosed-CycleCooling Water SystemWater ChemistryControl-Closed Cooling Water
 
Program (B.1.30.3)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-206External surfaces of steel components
 
including ducting, piping, ducting
 
closure bolting, and
 
containment
 
isolation piping external surfaces exposed to air -
 
indoor uncontrolled (external);
 
condensation (external) and air -
outdoor (external)
 
(3.2.1-31)
Loss of material due to general corrosionExternal SurfacesMonitoringSystem Walkdown Program (B.1.28)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1.12)
Steel piping and ducting components
 
and internal surfaces exposed to
 
air - indoor
 
uncontrolled (Internal)
 
(3.2.1-32)
Loss of material due to general corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting ComponentsSystem Walkdown Program (B.1.28)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1.13)
Steel encapsulation components exposed to air -
 
indoor uncontrolled (internal)
 
(3.2.1-33)
Loss of material due to general, pitting, and crevice corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting ComponentsNoneNot applicable (TheESF systems
 
include no steel
 
encapsulation
 
components.)
 
Steel piping, piping components, and
 
piping elements exposed to
 
condensation (internal)
 
(3.2.1-34)
Loss of material due to general, pitting, and crevice corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting ComponentsPeriodic Surveillanceand Preventive Maintenance
 
Program (B.1.22)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1.14)
Steel containment isolation piping and
 
components internal surfaces exposed to raw water (3.2.1-35)
Loss of material due to general, pitting, crevice, and MIC, and foulingOpen-Cycle CoolingWater SystemContainment Leak Rate Program (B.1.8);
Containment Inservice Inspection
 
Program (B.1.15.1)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1.15)
Steel heatexchanger components exposed to raw water (3.2.1-36)
Loss of material due to general, pitting, crevice, galvanic, and MIC, and
 
foulingOpen-Cycle CoolingWater SystemService WaterIntegrity Program (B.1.26); Periodic Surveillance and Preventive Maintenance (B.1.22)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1.16)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-207 Stainless steel piping, piping
 
components, and
 
piping elements exposed to raw water (3.2.1-37)
Loss of material dueto pitting, crevice, and MICOpen-Cycle CoolingWater SystemPeriodic Surveillanceand Preventive Maintenance (B.1.22)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1.17)
Stainless steel containment
 
isolation piping and
 
components internal surfaces exposed to raw water (3.2.1-38)
Loss of material dueto pitting, crevice, and MIC, and
 
foulingOpen-Cycle CoolingWater SystemNoneNot applicable(There are no
 
stainless steel
 
containment
 
isolation components exposed to raw water in the ESF systems.)
(See SER Section 3.2.2.3.8)
Stainless steel heatexchanger components exposed to raw water (3.2.1-39)
Loss of material dueto pitting, crevice, and MIC, and
 
foulingOpen-Cycle CoolingWater SystemService WaterIntegrity Program (B.1.26)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1)
Steel and stainless steel heat exchanger tubes (serviced by open-cycle cooling water) exposed to raw water (3.2.1-40)Reduction of heat transfer due to
 
foulingOpen-Cycle CoolingWater SystemService WaterIntegrity Program (B.1.26)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1)Copper alloy > 15 percent Zn piping, piping components, piping elements, and heat exchanger
 
components exposed to closed cycle cooling water
 
(3.2.1-41)
Loss of material dueto selective leachingSelective Leachingof MaterialsNoneNot applicable(There are no copper alloy > 15 percent zinc
 
components exposed to closed cycle cooling water
 
in the ESF systems.)
(See SER Section 3.2.2.3.8)Gray cast iron piping, piping
 
components, piping elements exposed to closed-cycle cooling water
 
(3.2.1-42)
Loss of material dueto selective leachingSelective Leachingof MaterialsSelective Leaching Program (B.1.25)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-208Gray cast iron piping, piping
 
components, and
 
piping elements exposed to soil
 
(3.2.1-43)
Loss of material dueto selective leachingSelective Leachingof MaterialsNoneNot applicable(There are no gray cast iron components exposed to soil in the ESF systems.)
(See SER Section 3.2.2.3.8)Gray cast iron motorcooler exposed to treated water
 
(3.2.1-44)
Loss of material dueto selective leachingSelective Leachingof MaterialsSelective Leaching Program (B.1.25)Consistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.2.2.1)
Aluminum, copperalloy > 15
 
percent Zn, and steel external
 
surfaces, bolting, and piping, piping
 
components, and
 
piping elements exposed to air with borated water
 
leakage (3.2.1-45)
Loss of material due to Boric acid corrosionBoric AcidCorrosionNoneNot applicable toBWRs Steel encapsulation components exposed to air with borated water
 
leakage (internal)
 
(3.2.1-46)
Loss of material due to general, pitting, crevice and boric acid corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting ComponentsNoneNot applicable toBWRs CASS piping, piping components, and
 
piping elements exposed to treated borated water
 
> 250C (> 482F)(3.2.1-47)
Loss of fracture toughness due to
 
thermal aging
 
embrittlementThermal Aging Embrittlement of
 
CASSNoneNot applicable toBWRs Stainless steel or stainless-steel-clad
 
steel piping, piping
 
components, piping
 
elements, and tanks (including safety
 
injection tanks/accumulators) exposed to treated borated water
 
> 60C (> 140F)(3.2.1-48)Cracking due to SCCWater ChemistryNoneNot applicable toBWRs Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-209 Stainless steel piping, piping
 
components, piping
 
elements, and tanks exposed to treated borated water
 
(3.2.1-49)
Loss of material due to pitting and crevice corrosionWater ChemistryNoneNot applicable toBWRs Aluminum piping, piping components, and piping elements exposed to air -
 
indoor uncontrolled (internal/external)
 
(3.2.1-50)NoneNoneNoneNot applicable ( See SER Section 3.2.2.1)Galvanized steelducting exposed to
 
air - indoor controlled (external)
 
(3.2.1-51)NoneNoneNoneNot applicableGlass pipingelements exposed
 
to air - indoor
 
uncontrolled (external),
lubricating oil, raw water, treated water, or treated borated water (3.2.1-52)NoneNoneNoneConsistent withGALL Report Galvanized steel
 
surfaces are evaluated as steel
 
in the ESF systems.)Stainless steel,copper alloy, and nickel alloy piping, piping components, and piping elements exposed to air -
 
indoor uncontrolled (external)
 
(3.2.1-53)NoneNoneNoneConsistent with GALL Report ( See
 
SER Section 3.2.2.1)
Steel piping, piping components, and
 
piping elements exposed to air -
 
indoor controlled (external)
 
(3.2.1-54)NoneNoneNoneNot applicable(There are no steel
 
components of the ESF systems in
 
indoor controlled air environments. All
 
indoor air environments are conservatively
 
considered to be
 
uncontrolled)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-210 Steel and stainless steel piping, piping
 
components, and
 
piping elements in
 
concrete (3.2.1-55)NoneNoneNoneNot applicable(There are no steel
 
or stainless steel
 
components in the ESF systems
 
embedded in concrete).
Steel, stainless steel, and copper alloy piping, piping
 
components, and
 
piping elements exposed to gas
 
(3.2.1-56)NoneNoneNoneConsistent with GALL Report ( See
 
SER Section 3.2.2.1)
Stainless steel andcopper alloy < 15
 
percent Zn piping, piping components, and piping elements exposed to air with borated water
 
leakage (3.2.1-57)NoneNoneNoneNot applicable toBWRsThe staff's review of the ESF systems component groups followed any one of severalapproaches. One approach, documented in SER Section 3.2.2.1, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.2.2.2, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.2.2.3, reviewed AMR results for components that the applicant indicated are not consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the ESF systems components is documented in SER Section 3.0.3.3.2.2.1  AMR Results Consistent with the GALL ReportSummary of Technical Information in the Application LRA Section 3.2.2.1 identifies the materials,environments, AERMs, and the following programs that manage aging effects for the ESF systems components:
* Buried Piping and Tanks Inspection Program
* Containment Leak Rate Program
* Flow-Accelerated Corrosion Program
* Heat Exchanger Monitoring Program
* Oil Analysis Program
* One-Time Inspection Program
* Periodic Surveillance and Preventive Maintenance Program
* Selective Leaching Program 3-211
* Service Water Integrity Program
* System Walkdown Program
* Water Chemistry Control - Auxiliary Systems Program
* Water Chemistry Control - BWR Program
* Water Chemistry Control - Closed Cooling Water ProgramStaff Evaluation. LRA Tables 3.2.2-1 through 3.2.2-7 summarize AMRs for the ESF systemscomponents and indicate AMRs claimed to be consistent with the GALL Report.For component groups evaluated in the GALL Report for which the applicant claimed consistencywith the report and for which it does not recommend further evaluation, the staff's audit and review determined whether the plant-specific components of these GALL Report component groups were bounded by the GALL Report evaluation.The applicant noted for each AMR line item how the information in the tables aligns with theinformation in the GALL Report. The staff audited those AMRs with notes A through E indicating how the AMR is consistent with the GALL Report.Note A indicates that the AMR line item is consistent with the GALL Report for component,material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP.
The staff audited these line items to verify consistency with the GALL Report and validity of the AMR for the site-specific conditions.Note B indicates that the AMR line item is consistent with the GALL Report for component,material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify consistency with the GALL Report and verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also determines whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions.Note C indicates that the component for the AMR line item, although different from, is consistentwith the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified in the GALL Report a different component with the same material, environment, aging effect, and AMP as the component under review. The staff audited these line items to verify consistency with the GALL Report. The staff also determines whether the AMR line item of the different component was applicable to the component under review and whether the AMR was valid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different from, is consistentwith the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component was applicable to the component under review and whether the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also determines whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions.
3-212Note E indicates that the AMR line item is consistent with the GALL Report for material,environment, and aging effect, but credits a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also determines whether the credited AMP would manage the aging effect consistently with the GALL AMP and whether the AMR was valid for the site-specific conditions.The staff audited and reviewed the information in the LRA. The staff did not repeat its review ofthe matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs.The staff reviewed the LRA to confirm that the applicant: (a) provided a brief description of thesystem, components, materials, and environments; (b) stated that the applicable aging effects were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the ESF systems components that are subject to an AMR. On the basis of its audit and review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.2.1, the applicant's references to the GALL Report are acceptable and no further staff review is required.3.2.2.1.1  Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-3, the applicant stated that the WaterChemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material for stainless steel containment isolation piping and components internal surfaces exposed to treated water of the ESF system. During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. The staff reviewed the applicant's Water Chemistry Control - BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-3 within the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.The staff evaluated the applicant's claim of consistency with the GALL Report. The staff alsoreviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed consistent with its AMRs. Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-2133.2.2.1.2  Loss of Material Due to Pitting and Crevice CorrosionIn the discussion column of LRA Table 3.2.1, Item 3.2.1-5, the applicant stated that the WaterChemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in stainless steel and aluminum piping and piping components exposed to treated water of the ESF system.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. The staff reviewed the applicant's Water Chemistry Control - BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-5 within the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.2.2.1.3  Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-6, the applicant stated that the OilAnalysis Program manages loss of material in stainless steel and copper alloy components.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. In a letter dated July 14, 2006, the applicant revised the LRA so that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program.The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection Program.These evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. The staff found each program acceptable. With the change discussed above, the applicant is managing the loss of material due to pitting, and crevice corrosion of stainless steel and copper alloy piping, piping components, and piping elements exposed to lubricating oil in a manner thatis consistent with the GALL Report and therefore acceptable to the staff. In addition, this aging effect is also managed for carbon steel gauges, filter housings, heater housings, pump casings, strainer housings, tanks, gear boxes, and heat exchanger shells as well as gray cast iron valve bodies exposed to lubricating oil.On the basis of its review, the staff finds that the applicant, with the change in the applicationidentified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.2.2.1.4  Reduction of Heat Transfer Due to Fouling In the discussion column of LRA Table 3.2.1, Item 3.2.1-9, the applicant stated that the OilAnalysis Program manages reduction of heat transfer in steel, stainless steel and copper alloy components.
3-214During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. In a letter dated July 14, 2006, the applicant revised the LRA so that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program.The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection Program.These evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. With the change discussed above, the applicant is managing the reduction of heat transfer due to fouling of steel, stainless steel and copper alloy heat exchanger tubes exposed to lubricating oil in a manner that is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant, with the change in the applicationidentified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.2.2.1.5  Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-10, the applicant stated that the WaterChemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in stainless steel heat exchanger tubes exposed to treated water of the ESF system. During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. The staff reviewed the applicant's Water Chemistry Control - BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-10 within the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.2.2.1.6  Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-14, the applicant stated that the WaterChemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in steel piping, piping components, and piping elements exposed to treated water of the ESF system. During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. The staff reviewed the applicant's Water Chemistry Control - BWR Program and One-Time Inspection Program. These 3-215evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The stafffound each program acceptable. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-14 within the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.2.2.1.7  Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-15, the applicant stated that the WaterChemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in steel containment isolation piping, piping components, and piping elements internal surfaces exposed to treated of the ESFsystem. During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. The staff reviewed the applicant's Water Chemistry Control - BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-15 within the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.2.2.1.8  Loss of Material Due to General, Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-16 the applicant stated that the OilAnalysis Program manages loss of material in steel components.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. In a letter dated July 14, 2006, the applicant revised the LRA so that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program.The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection Program.These evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. The staff found each program acceptable. With the change discussed above, the applicant is managing the loss of material due to general pitting, and crevice corrosion of steel piping, pipingcomponents, and piping elements exposed to lubricating oil in a manner that is consistent with the GALL Report and therefore acceptable to the staff.
On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
3-2163.2.2.1.9  Cracking Due to Stress Corrosion Cracking and Intergranular Stress CorrosionCrackingIn the discussion column of LRA Table 3.2.1, Item 3.2.1-18, the applicant stated that the WaterChemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage cracking due to SCC and IGSCC in stainless steel piping, piping components, and piping elements of the ESF system. The VYNPS WaterChemistry Control - BWR Program optimizes the primary water chemistry to minimize the potential for cracking. This is accomplished by limiting the levels of contaminants in the reactor coolant system that could cause cracking. Additionally, VYNPS has instituted hydrogen water chemistry with noble metals to limit the potential for IGSCC through the reduction of dissolved oxygen in the treated water. During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. The staff reviewed the applicant's Water Chemistry Control - BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable.On the basis of its review, the staff finds that managing cracking due to SCC and IGSCC WaterChemistry Control-BWR Program, One-Time Inspection Program, and Inservice Inspection Program appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.2.2.1.10  Wall Thinning Due to Flow-Accelerated Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-19, the applicant stated that theFlow-Accelerated Corrosion Program will be used to manage wall thinning in steel piping, pipingcomponents, and piping elements exposed to steam or treated water of the ESF system.The staff reviewed the applicant's Flow-Accelerated Corrosion Program. This evaluation isdocumented in SER Section 3.0.3.1.2, which the staff found acceptable. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-19 within the population that is subject to the Flow-Accelerated Corrosion Program. This is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.2.2.1.11  Loss of Material Due to General, Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-23 the applicant stated that the SystemWalkdown Program manages loss of material due to general, pitting and crevice corrosion exposed to air outdoor (external) or air indoor uncontrolled (external) for steel bolting and closurebolting components.
3-217During the audit and review, the staff asked the applicant to clarify the basis for using its SystemWalkdown Program to manage aging of carbon steel bolting instead the AMP recommended by the GALL Report. In a letter dated July 6, 2006, the applicant agreed to prepare and submit an AMP consistent with GALL AMP XI.M18, "Bolting Integrity," for review and approval. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staff's evaluation of this program is documented in SER Section 3.0.3.2.19. With this change, the applicant's management of loss of material due to general, pitting and crevice corrosion of steel bolting and closure bolting, will be consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant, with the change in the applicationidentified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.2.2.1.12  Loss of Material Due to General Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-31, the applicant stated that the SystemWalkdown Program will be used to manage loss of material to external surfaces of steel components including ducting, piping, ducting closure bolting, and containment isolation pipingexternal surfaces exposed to air-indoor uncontrolled (external); condensation (external) and air-outdoor (external) in the ESF system.The staff reviewed the applicant's System Walkdown Program. This evaluation is documented inSER Section 3.0.3.1.9, which the staff found acceptable. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-31 within the population that is subject to the System Walkdown Program.
This is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.2.2.1.13  Loss of Material Due to General Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-32, the applicant stated that the SystemWalkdown Program will be used to manage loss of material to steel piping, fan housing, valve body, and ducting components and internal surfaces exposed to air-indoor uncontrolled (internal) in the ESF, SA, and HVAC systems.The staff reviewed the applicant's System Walkdown Program. This evaluation is documented inSER Section 3.0.3.1.9. The staff found the program acceptable. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-32 within the population that is subject to the System Walkdown Program. This is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
3-2183.2.2.1.14  Loss of Material Due to General, Pitting and Crevice CorrosionIn the discussion column of LRA Table 3.2.1, Item 3.2.1-34, the applicant stated that the PeriodicSurveillance and Preventive Maintenance Program will be used to manage loss of material to steel piping, piping components and piping elements exposed to condensation (internal) in theESF system.The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program.This evaluation is documented in SER Section 3.0.3.3.5, which the staff found acceptable.
Preventive maintenance activities and periodic surveillances provide for periodic component inspections and testing to detect aging effects. Inspection intervals are established such that they provide timely detection of degradation. Inspection intervals are dependent on component material and environment and take into consideration industry and plant-specific operating experience and manufacturers' recommendations. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-34 within the population that is subject to the Periodic Surveillance and Preventive Maintenance Program. This is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.2.2.1.15  Loss of Material Due to General, Pitting, Crevice Corrosion,Microbiologically-Influenced Corrosion and FoulingIn the discussion column of LRA Table 3.2.1, Item 3.2.1-35, the applicant stated that theContainment Leak Rate Program will be used to manage loss of material due to general, pitting, crevice corrosion, MIC and fouling of steel containment isolation piping and components internal surfaces exposed to raw water in the ESF system.The staff reviewed the applicant's Containment Leak Rate Program. This evaluation isdocumented in SER Section 3.0.3.2.8, which the staff found acceptable. During the audit and review, the staff confirmed that the Containment Leak Rate Program is supplemented by the Containment Inservice Inspection Program, which performs inspections to validate the Containment Leak Rate Program. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-35 within the population that is subject to the Containment Leak Rate Program. This is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
3-2193.2.2.1.16  Loss of Material Due to General, Pitting, Crevice, Galvanic,Microbiologically-Influenced Corrosion and FoulingIn the discussion column of LRA Table 3.2.1, Item 3.2.1-36, the applicant stated that the ServiceWater Integrity Program manages loss of material for carbon steel components exposed to raw water and for other piping components of the SGTS while the Periodic Surveillance and Preventive Maintenance Program manages loss of material for carbon steel components exposed to raw water in the ESF system.The staff reviewed the applicant's Service Water Integrity Program and Periodic Surveillance andPreventive Maintenance Program. These evaluations are documented in SER Sections 3.0.3.2.16 and 3.0.3.3.5, respectively. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-36 within the population that is subject to the Service Water Integrity and Periodic Surveillance and Preventive Maintenance Programs. This is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.2.2.1.17  Loss of Material Due to Pitting, Crevice Corrosion and Microbiologically-InfluencedCorrosionIn the discussion column of LRA Table 3.2.1, Item 3.2.1-37, the applicant stated that the PeriodicSurveillance and Preventive Maintenance Program will be used to manage loss of material due to pitting, crevice corrosion, MIC and fouling of stainless steel piping, piping components and pipingelements exposed to raw water in the ESF system.The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program.This evaluation is documented in SER Section 3.0.3.3.5. This is consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.2.2.1.18  Loss of Preload Due to Thermal Effects, Gasket Creep and Self-Loosening In the discussion column of LRA Table 3.2.1, Item 3.2.1-24 the applicant stated that the loss ofpreload was not an AERM.During the audit and review, the staff asked the applicant to justify the position that was taken innot managing the aging effect for loss of preload, instead of using the AMP recommended in the GALL Report. In a letter dated July 6, 2006, the applicant committed (Commitment #34) to prepare and submit an AMP consistent with GALL AMP XI.M18, "Bolting Integrity," for review and approval. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staff's evaluation of this program is documented in SER Section 3.0.3.2.19, which the staff found acceptable. In addition, by letter dated January 4, 2007, the applicant provided clarification that its Bolting Integrity Program addresses 3-220all bolting. With this change, the applicant's management of loss of preload due to thermaleffects, gasket creep and self loosening of steel closure bolting, will be consistent with the GALL Report and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant, with the change in the application andCommitment #34 identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the associated aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed consistent with the AMRs in the GALL Report. Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.2.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is RecommendedSummary of Technical Information in the Application. In LRA Section 3.2.2.2, the applicant furtherevaluates aging management, as recommended by the GALL Report, for the ESF systems components and provides information concerning how it will manage the following aging effects:
* cumulative fatigue damage
* loss of material due to cladding
* loss of material due to pitting and crevice corrosion
* reduction of heat transfer due to fouling
* hardening and loss of strength due to elastomer degradation
* loss of material due to erosion
* loss of material due to general corrosion and fouling
* loss of material due to general, pitting, and crevice corrosion
* loss of material due to general, pitting, crevice, and MIC
* quality assurance for aging management of nonsafety-related componentsStaff Evaluation. For component groups evaluated in the GALL Report, for which the applicantclaimed consistency with the report and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations against the criteria contained in SRP-LR Section 3.2.2.2. The staff's review of the applicant's further evaluation follows.
3-2213.2.2.2.1  Cumulative Fatigue DamageLRA Section 3.2.2.2.1 states that fatigue is a TLAA, as required by 10 CFR 54.3. Applicants mustevaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.3.2.2.2.2  Loss of Material Due to Cladding The staff reviewed LRA Section 3.2.2.2.2 against the criteria in SRP-LR Section 3.2.2.2.2.
In LRA Section 3.2.2.2.2, the applicant stated that for the cracking due to underclad cracking, thisaging effect is not applicable to VYNPS. This item covers underclad cracking of cladding on PWR steel pump casings. VYNPS is a BWR and does not have charging pumps or steel pump casings with stainless steel cladding.SRP-LR Section 3.2.2.2.2 states that loss of material due to cladding breach may occur in PWRsteel pump casings with stainless steel cladding exposed to treated borated water. The GALLReport references IN 94-63, "Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks," and recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed.The staff determined that the cracking due to underclad cracking is not applicable to VYNPS.
On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.3.2.2.2.3  Loss of Material Due to Pitting and Crevice Corrosion The staff reviewed LRA Section 3.2.2.2.3 against the following SRP-LR Section 3.2.2.2.3 criteria:
  (1)LRA Section 3.2.2.2.3 addresses loss of material of internal surfaces of stainless steelpiping and components in ESF systems exposed to treated water due to pitting and crevice corrosion. SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosionmay occur on internal surfaces of stainless steel containment isolation piping, pipingcomponents, and piping elements exposed to treated water. The existing AMP monitors and controls water chemistry to mitigate degradation. However, control of water chemistry does not preclude loss of material due to pitting and crevice corrosion at locations with stagnant flow conditions; therefore, the effectiveness of water chemistry control programs should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to verify the effectiveness of water chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the component's intended functions will be maintained during the period of extended operation.
3-222The LRA states that loss of material due to pitting and crevice corrosion for internalsurfaces of stainless steel piping and components in ESF systems exposed to treated water is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicant's Water Chemistry Control-BWR Program will be confirmed by VYNPS the One-Time Inspection Program, through an inspection of a representative sample of components including areas of stagnant flow.The use of the One-Time Inspection Program in conjunction with the Water ChemistryControl-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.3 and therefore is acceptable.  (2)LRA Section 3.2.2.2.3 addresses the loss of material due to pitting and crevice corrosion,this aging effect is not applicable to VYNPS. At VYNPS, there are no stainless steel ESF system components that are in contact with a soil environment. This item is therefore not
 
applicable.SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevicecorrosion may occur in stainless steel piping, piping components, and pipingelements exposed to soil. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed.The staff determines that stainless steel components are not present in a soilenvironment, therefore, the loss of material due to pitting and crevice corrosion is not applicable at VYNPS.On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS.  (3)LRA Section 3.2.2.2.3 addresses the loss of material of BWR stainless steel andaluminum piping and piping components exposed to treated water due to pitting and crevice corrosion.SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosionmay occur in BWR stainless steel and aluminum piping, piping components, and pipingelements exposed to treated water. The existing AMP monitors and controls water chemistry for BWRs to mitigate degradation. However, control of water chemistry does not preclude loss of material due to pitting and crevice corrosion at locations with stagnant flow conditions; therefore, the effectiveness of water chemistry control programs should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to verify the effectiveness of water chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the component's intended functions will be maintained during the period of extended operation.
3-223The LRA states that loss of material from pitting and crevice corrosion for BWR stainlesssteel and aluminum piping and piping components exposed to treated water is managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components including areas of stagnant flow.The applicant's Water Chemistry Control-BWR Program relies on monitoring and controlof water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.3 and therefore is acceptable.  (4)LRA Section 3.2.2.2.3 addresses loss of material of copper alloy and stainless steel pipingand components in ESF systems that are exposed to lubricating oil due to pitting and crevice corrosion.SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosionmay occur in stainless steel and copper alloy piping, piping components, and pipingelements exposed to lubricating oil. The existing program periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation to verify the effectiveness of lubricating oil programs. A one-time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The LRA states that loss of material from pitting and crevice corrosion could occur forcopper alloy and stainless steel piping and components in ESF systems that are exposed to lubricating oil. Loss of material is managed by the Oil Analysis Program, which includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion.
Operating experience at VYNPS has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion has not and will not affect the intended functions of these components.The applicant's Oil Analysis Program maintains oil systems free of contaminants (primarilywater and particulates) thereby preserving an environment that is not conducive to loss of material. The staff reviewed the applicant's plant-specific and industry operating experience and confirmed that the program is maintaining contaminants within limits such that corrosion has not affected the intended functions of these components. In a letter dated July 14, 2006, the applicant stated that the Oil Analysis Program will be supplemented by the One-Time Inspection Program, to verify its effectiveness. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.3 and therefore is acceptable.
3-224  (5)LRA Section 3.2.2.2.3 addresses the loss of material due to pitting and crevice corrosion,this aging effect is not applicable to VYNPS. Loss of material from pitting and crevice corrosion could occur for partially encased stainless steel tanks exposed to raw water due to cracking of the perimeter seal from weathering. At VYNPS, there are no outdoor stainless steel tanks in the ESF systems.SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosionmay occur in partially encased stainless steel tanks exposed to raw water due to cracking of the perimeter seal from weathering. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that this aging effect is adequately managed. The GALL Report recommends that a plant-specific AMP be evaluated because moisture and water can egress under the tank if the perimeter seal is degraded.The staff determines through discussions with the applicant's technical personnel, that theloss of material due to pitting and crevice corrosion is therefore not applicable.On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS.  (6)LRA Section 3.2.2.2.3 addresses loss of material of BWR stainless steel piping and pipingcomponents internally exposed to condensation due to pitting and crevice corrosion.SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosionmay occur in stainless steel piping, piping components, piping elements, and tanksexposed to internal condensation. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed.The LRA states that loss of material from pitting and crevice corrosion for BWR stainlesssteel piping and piping components internally exposed to condensation is managed by the Periodic Surveillance and Preventive Maintenance Program. This program uses visual and other NDE techniques to manage loss of material for these components.The applicant's Periodic Surveillance and Preventive Maintenance Program is aplant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for loss of material from pitting and crevice corrosion which may occur for stainless steel piping, pipingcomponents, piping elements, and tanks exposed to internal condensation. It is therefore acceptable to the staff.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.2.2.2.3 criteria. For those line items that apply to LRA Section 3.2.2.2.3, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-2253.2.2.2.4  Reduction of Heat Transfer Due to FoulingThe staff reviewed LRA Section 3.2.2.2.4 against the following SRP-LR Section 3.2.2.2.4 criteria:
  (1)LRA Section 3.2.2.2.4 addresses the reduction of heat transfer of copper alloy heatexchanger tubes exposed to lubricating oil in ESF systems due to fouling.SRP-LR Section 3.2.2.2.4 states that reduction of heat transfer due to fouling may occurin steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil.
The existing AMP monitors and controls lube oil chemistry to mitigate reduction of heat transfer due to fouling. However, control of lube oil chemistry may not always be fully effective in precluding fouling; therefore, the effectiveness of lube oil chemistry control should be verified to ensure that fouling does not occur. The GALL Report recommends further evaluation of programs to verify the effectiveness of lube oil chemistry control. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the component's intended functions will be maintained during the period of extended operation. The LRA states that reduction of heat transfer due to fouling for copper alloy heatexchanger tubes exposed to lubricating oil in ESF systems is managed by the Oil Analysis Program. There are no stainless steel or steel heat exchanger tubes exposed to lubricating oil in the ESF systems. This program includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to fouling. Operating experience has confirmed the effectiveness of this program in maintaining contaminants within limits such that fouling has not and will not affect the intended functions of these components.The applicant's Oil Analysis Program maintains oil systems free of contaminants (primarilywater and particulates) thereby preserving an environment that is not conducive to fouling.
The staff reviewed the applicant's plant-specific and industry operating experience and confirmed that the program is maintaining contaminants within limits such that corrosion has not affected the intended functions of these components. In a letter dated July 14, 2006, the applicant stated that the Oil Analysis Program will be supplemented by the One-Time Inspection Program, to verify its effectiveness. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.4 and is therefore acceptable.  (2)LRA Section 3.2.2.2.4 addresses the reduction of heat transfer of stainless steel heatexchanger tubes exposed to treated water in ESF systems due to fouling.SRP-LR Section 3.2.2.2.4 states that reduction of heat transfer due to fouling may occurin stainless steel heat exchanger tubes exposed to treated water. The existing program controls water chemistry to manage reduction of heat transfer due to fouling. However, control of water chemistry may be inadequate; therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that reduction of heat transfer due to fouling does not occur. A one-time inspection is an acceptable method to ensure that reduction of heat transfer does not occur and that component intended functions will be maintained during the period of extended operation.
3-226The LRA states that reduction of heat transfer due to fouling for stainless steel heatexchanger tubes exposed to treated water in ESF systems is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicant's Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including areas of stagnant flow.The applicant's Water Chemistry Control-BWR Program relies on monitoring and controlof water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.4 and is therefore acceptable.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.2.2.2.4 criteria. For those line items that apply to LRA Section 3.2.2.2.4, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.2.2.2.5  Hardening and Loss of Strength Due to Elastomer Degradation The staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5.
LRA Section 3.2.2.2.5 addresses the hardening and loss of strength due to elastomerdegradation, this aging effect is not applicable to VYNPS. At VYNPS, there are no elastomeric components in the ESF systems. SRP-LR Section 3.2.2.2.5 states that hardening and loss of strength due to elastomerdegradation may occur in elastomer seals and components of the BWR SGTS ductwork and filters exposed to air - indoor uncontrolled. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed.The staff determines through discussions with the applicant's technical personnel that thehardening and loss of strength due to elastomer degradation is not applicable.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.3.2.2.2.6  Loss of Material Due to Erosion The staff reviewed LRA Section 3.2.2.2.6 against the criteria in SRP-LR Section 3.2.2.2.6.
LRA Section 3.2.2.2.6 addresses the loss of material due to erosion, this aging effect is notapplicable to VYNPS. This discussion refers to stainless steel high pressure safety injection(HPSI) pump miniflow recirculation orifice exposed to treated borated water. VYNPS is a BWR and has no HPSI pump miniflow orifice and as such this item is not applicable.
3-227SRP-LR Section 3.2.2.2.6 states that loss of material due to erosion may occur in the stainlesssteel HPSI pump miniflow recirculation orifice exposed to treated borated water. The GALL Report recommends that plant-specific AMPs be evaluated for erosion of the orifice due to extended use of the centrifugal HPSI pump for normal charging. The GALL Report references Licensee Event Report 50-275/94-023 for evidence of erosion. Further evaluation is recommended to ensure that the aging effect is adequately managed.The staff determines, through discussions with the applicant's technical personnel, that the lossof material due to erosion is not applicable.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.3.2.2.2.7  Loss of Material Due to General Corrosion and Fouling The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP-LR Section 3.2.2.2.7.
LRA Section 3.2.2.2.7 addresses the loss of material due to general corrosion and fouling, thisaging effect is not applicable to VYNPS. This item refers to loss of material due to general corrosion and fouling occurring for steel drywell and suppression chamber spray system nozzle and flow orifice internal surfaces exposed to air-indoor uncontrolled (internal). At VYNPS, the spray nozzles are copper alloy and are not subject to loss of material due to general corrosion in an indoor air environment. There are also no orifices in ECCS systems exposed to an indoor air environment (internal).SRP-LR Section 3.2.2.2.7 states that loss of material due to general corrosion and fouling mayoccur on steel drywell and suppression chamber spray system nozzle and flow orifice internal surfaces exposed to air-indoor uncontrolled and may cause plugging of the spray nozzles and flow orifices. This aging mechanism and effect will apply since the spray nozzles and flow orifices are occasionally wetted even though this system is mostly on standby. The wetting and drying of these components can accelerate corrosion and fouling. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed.The staff determined, through discussions with the applicant's technical personnel, that the lossof material due to general corrosion and fouling in steel drywell and suppression chamber spray system nozzle and flow orifice internal surfaces exposed to air-indoor uncontrolled (internal) is not
 
applicable.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.3.2.2.2.8  Loss of Material Due to General, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.2.2.2.8 against the following SRP-LR Section 3.2.2.2.8 criteria:
  (1)LRA Section 3.2.2.2.8 addresses the loss of material of BWR steel piping andcomponents in ESF systems exposed to treated water due to general, pitting, and crevice
 
corrosion.
3-228SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevicecorrosion may occur in BWR steel piping, piping components, and piping elementsexposed to treated water. The existing AMP monitors and controls water chemistry for BWRs to mitigate degradation. However, control of water chemistry does not preclude loss of material due to general, pitting, and crevice corrosion at locations with stagnant flow conditions; therefore, the effectiveness of water chemistry control programs should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to verify the effectiveness of water chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the component's intended functions will be maintained during the period of extended operation.The LRA states that loss of material due to general, pitting and crevice corrosion for BWRsteel piping and components in ESF systems exposed to treated water is managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including areas of stagnant flow.The applicant's Water Chemistry Control-BWR Program relies on monitoring and controlof water chemistry based on EPRI Report 1008192 (BWRVIP-130). The One-Time Inspection Program is used to verify the effectiveness through inspection of a representative inspection including stagnant and low flow areas. The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.8 and is therefore acceptable.  (2)LRA Section 3.2.2.2.8 addresses the loss of material of internal surfaces of primarycontainment penetration steel piping and components exposed to treated water due to general, pitting and crevice corrosion.
SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevice corrosion may occur on the internal surfaces of steel containment isolation piping, pipingcomponents, and piping elements exposed to treated water. The existing AMP monitors and controls water chemistry to mitigate degradation. However, control of water chemistry does not preclude loss of material due to general, pitting, and crevice corrosion at locations with stagnant flow conditions; therefore, the effectiveness of water chemistry control programs should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to verify the effectiveness of water chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the component's intended functions will be maintained during the period of extended operation.The LRA states that the loss of material due to general, pitting and crevice corrosion forinternal surfaces of primary containment penetration steel piping and components exposed to treated water is managed by the Water Chemistry Control-BWR Program. The 3-229effectiveness of the Water Chemistry Control-BWR Program will be confirmed by theOne-Time Inspection Program, through an inspection of a representative sample of components including areas of stagnant flow.The use of the One-Time Inspection Program in conjunction with the Water ChemistryControl-BWR Program provides both the preventive and inspection elements. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.8 and is therefore acceptable.  (3)LRA Section 3.2.2.2.8 addresses loss of material of steel piping and components in ESFsystems exposed to lubricating oil due to general, pitting and crevice corrosion.SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevicecorrosion may occur in steel piping, piping components, and piping elements exposed tolubricating oil. The existing program periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation to verify the effectiveness of lubricating oil programs. A one-time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The LRA states that loss of material due to general, pitting and crevice corrosion for steelpiping and components in ESF systems exposed to lubricating oil is managed by the Oil Analysis Program. This program includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. Operating experience has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion has not and will not affect the intended functions of these components.The applicant's Oil Analysis Program maintains oil systems free of contaminants (primarilywater and particulates) thereby preserving an environment that is not conducive to fouling.
The staff reviewed the applicant's plant-specific and industry operating experience and confirmed that the program is maintaining contaminants within limits such that corrosion has not affected the intended functions of these components. In a letter dated July 14, 2006, the applicant stated that its Oil Analysis Program will be supplemented by the One-Time Inspection Program, to verify its effectiveness. The staff finds this combination satisfies the criteria of SRP-LR Section 3.2.2.2.8 and is therefore acceptable.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.2.2.2.8 criteria. For those line items that apply to LRA Section 3.2.2.2.8, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-2303.2.2.2.9  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-InfluencedCorrosionThe staff reviewed LRA Section 3.2.2.2.9 against the criteria in SRP-LR Section 3.2.2.2.9.
LRA Section 3.2.2.2.9 addresses loss of material of steel (with or without coating or wrapping)piping and piping components buried in soil in ESF systems due to general, pitting, crevice, andMIC.SRP-LR Section 3.2.2.2.9 states that loss of material due to general, pitting, crevice, and MICmay occur in steel (with or without coating or wrapping) piping, piping components, and pipingelements buried in soil. Buried piping and tanks inspection programs rely on industry practice, frequency of pipe excavation, and operating experience to manage the aging effects of loss of material from general, pitting, and crevice corrosion, and MIC. The effectiveness of the buried piping and tanks inspection program should be verified by evaluation of an applicant's inspection frequency and operating experience with buried components to ensure that loss of material does not occur.The LRA states that loss of material due to general, pitting, crevice, and MIC for steel (with orwithout coating or wrapping) piping and piping components buried in soil in ESF systems is managed by the Buried Piping Inspection Program. There are no buried tanks in the ESF systems. The applicant's Buried Piping Inspection Program will include: (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel components. Buried components will be inspected when excavated during maintenance. An inspection will be performed within 10 years of entering the period of extended operation, unless an opportunistic inspection occurred within this 10-year period.The staff confirmed that buried piping has already been inspected within the final 10-year periodbefore the period of extended operation. Therefore, even if no other buried piping is examined before the period of extended operation, VYNPS has followed staff guidance regarding the examination of buried piping through the end of the current operating license. The proposed schedule for inspection (if there is no other opportunity) is consistent with the staff's guidance and therefore acceptable to the staff.Based on the program identified above, the staff concludes that it meets SRP-LRSection 3.2.2.2.9 criteria. For those line items that apply to LRA Section 3.2.2.2.9, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-2313.2.2.2.10  Quality Assurance for Aging Management of Nonsafety-Related ComponentsSER Section 3.0.4 documents the staff's evaluation of the applicant's QA program, which thestaff found acceptable.
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determines that the applicant adequately addressed the issues that were further evaluated. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.2.2.3  AMR Results Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.2.2-1 through 3.2.2-7, thestaff reviewed additional details of the AMR results for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report.In LRA Tables 3.2.2-1 through 3.2.2-7, the applicant indicated, via notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information concerning how the aging effects will be managed. Specifically, note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.Staff Evaluation. For component type, material, and environment combinations that are notevaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine whether it had demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff's evaluation is discussed in the following sections.3.2.2.3.1  Residual Heat Removal System Summary of Aging Management Evaluation - LRATable 3.2.2-1The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for theRHRS component groups.In LRA Table 3.2.2-1, the applicant proposed to manage cracking of stainless steel heatexchanger tubes exposed to a raw water environment using the Service Water Integrity Program.
3-232The staff reviewed the applicant's Service Water Integrity Program and its evaluation isdocumented in SER Section 3.0.3.2.16. The applicant stated, in the LRA, that this program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the SWS will be managed for the period of extended operation. The SWS includes the SW, RHRSW, and alternate cooling systems. The program includes surveillance and control techniques to manage aging effects in the SWS or SCs serviced by the SWS. The staff finds the cracking of stainless steel heat exchanger tubes exposed to raw water environments are effectively managed using the Service Water Integrity Program. On this basis, the staff finds that management of cracking in the RHRS is acceptable.In LRA Table 3.2.2-1, the applicant proposed to manage loss or material of carbon steel materialsfor component types of bolting exposed to air-indoor (external) environment using the System Walkdown Program.During the audit and review, the staff asked the applicant to clarify the basis for using its SystemWalkdown Program to manage aging of carbon steel bolting instead of the recommended GALL AMP XI.M18, "Bolting Integrity." By a letter dated July 6, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18. By a letter dated October 17, 2006, the applicant revised its LRA to include a discussion of its Bolting Integrity Program in LRA Section B.1.31. The staff's evaluation of the applicant's System Walkdown Program and Bolting Integrity Program is documented in SER Sections 3.0.3.1.9 and in 3.0.3.2.19, respectively. The staff finds that the applicant's Bolting Integrity Program conformed to the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI and that the applicant's System Walkdown Program is comprised of inspections of external surfaces of components subject to an AMR. On this basis, the staff finds that the applicant's management of carbon steel bolting in the RHRS consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.2.2.3.2  Core Spray System Summary of Aging Management Evaluation - LRA Table 3.2.2-2 The staff reviewed LRA Table 3.2.2-2, which summarizes the results of AMR evaluations for theCSS component groups.In LRA Table 3.2.2-2, the applicant proposed to manage loss or material of carbon steel materialsfor component types of bolting exposed to air-indoor (external) environment using the System Walkdown Program.During the audit and review, the staff asked the applicant to clarify the basis for using the SystemWalkdown Program to manage aging of carbon steel bolting instead of the recommended GALL AMP XI.M18, "Bolting Integrity." By a letter dated July 6, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18. By a letter dated 3-233October 17, 2006, the applicant revised its LRA to include a discussion of the Bolting IntegrityProgram in LRA Section B.1.31. The applicant's System Walkdown Program and Bolting Integrity Program are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff finds that the applicant's Bolting Integrity Program conformed to the GALL Report and is adequate. On this basis, the staff finds that the applicant's management of carbon steel bolting, in the CSS, is consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.2.2.3.3  Automatic Depressurization System Summary of Aging Management Evaluation - LRATable 3.2.2-3The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for theautomatic depressurization system component groups.In LRA Table 3.2.2-3, the applicant proposed to manage loss or material of carbon steel materialsfor component types of bolting exposed to air-indoor (external) environment using the System Walkdown Program.During the audit and review, the staff asked the applicant to clarify the basis for using the SystemWalkdown Program to manage aging of carbon steel bolting instead of the recommended GALL AMP XI.M18, "Bolting Integrity." By letter dated July 14, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18. By a letter dated October 17, 2006, the applicant revised its LRA to include a discussion of the Bolting Integrity Program in LRA Section B.1.31. The staff's evaluation of the applicant's System Walkdown Program and Bolting Integrity Program are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff finds that the applicant's Bolting Integrity Program conformed to the GALL Report and is adequate. On this basis, the staff finds that the applicant's management of carbon steel bolting, in the automatic depressurization system, consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.2.2.3.4  High Pressure Coolant Injection System Summary of Aging Management Evaluation -LRA Table 3.2.2-4The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for theHPCIS component groups.
3-234In LRA Table 3.2.2-4, the applicant proposed to manage loss of material wear of copper alloyheat exchanger tubes exposed to lube oil and treated water environments using the Heat Exchanger Monitoring Program.The staff reviewed the applicant's Heat Exchanger Monitoring Program and its evaluation isdocumented in SER Section 3.0.3.3.1. The Heat Exchanger Monitoring Program will be used to inspect heat exchanger tubes for degradation using eddy current inspections. As stated in the LRA, this AMP is credited with managing the aging effect of loss of material on the pressure boundary intended function for the components for which this AMP is credited. The staff finds the aging effect of loss of material due to wear of copper alloy heat exchanger tubes exposed to lube oil and treated water are effectively managed using Heat Exchanger Monitoring Program. On this basis, the staff finds that management of loss of material wear in the HPCIS is acceptable.In LRA Table 3.2.2-4, the applicant proposed to manage cracking of stainless steel orifice, tubing,and valve body exposed to lube oil environments using the Oil Analysis Program.The staff reviewed the Oil Analysis Program and its evaluation is documented in SERSection 3.0.3.2.13. LRA Section A.2.1.22, states that the Oil Analysis Program maintains oil systems free of contaminants (primarily water and particulates) thereby preserving an environment that is not conducive to loss of material, cracking, or fouling. Activities include sampling and analysis of lubricating oil for detrimental contaminants, water, and particulates. In a letter dated July 14, 2006, the applicant stated that the effectiveness of the Oil Analysis Program will be confirmed by the One-Time Inspection Program. On this basis the staff finds that the aging effect of cracking of stainless steel material exposed to a lube oil environment is effectively managed using the Oil Analysis Program and that management of cracking in the HPCIS is acceptable.In LRA Table 3.2.2-4, the applicant proposed to manage loss or material of carbon steel andstainless steel materials for component types of bolting exposed to an air-indoor (external) andair-outdoor (external) environment using the System Walkdown Program.During the audit and review, the staff asked the applicant to clarify the basis for using the SystemWalkdown Program to manage aging of carbon steel and stainless steel bolting instead of the recommended GALL AMP XI.M18, "Bolting Integrity." By a letter dated July 14, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18l. By a letter dated October 17, 2006, the applicant revised its LRA to include a discussion of the Bolting Integrity Program in LRA Section B.1.31. The staff's evaluation of the applicant's System Walkdown Program and Bolting Integrity Program in documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff finds that the applicant's Bolting Integrity Program conformed to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI and the applicant's System Walkdown Program comprised of inspections of external surfaces of components subject to an AMR. On this basis, the staff finds that the applicant's management of carbon steel and stainless steel bolting, in the HPCIS, consistent with the GALL Report and therefore acceptable.
3-235On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.2.2.3.5  Reactor Core Isolation Cooling System Summary of Aging Management Evaluation -LRA Table 3.2.2-5The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for thereactor core isolation cooling system (RCICS) component groups.In LRA Table 3.2.2-5, the applicant proposed to manage loss of material wear of copper alloy andaluminum heat exchanger tubes and steam heaters exposed to treated water and a lube oil environment using the Heat Exchanger Monitoring Program.The staff review the Heat Exchanger Monitoring Program and its evaluation is documented inSER Section 3.0.3.3.1. The Heat Exchanger Monitoring Program will inspect heat exchangers for degradation. Loss of material wear is the aging effect managed by this program. Representative tubes within the sample population of heat exchangers will be eddy current tested at a frequency determined by internal and external operating experience to ensure that effects of aging are identified prior to loss of intended function. The sample population of heat exchangers includes the HPCI GSC, HPCI lube oil cooler, RCIC lube oil cooler, CST steam reheat coil, drywell atmospheric cooling units (RRU-1, 2, 3 and 4), RRP seal water coolers, RRP motor upper and lower bearing oil coolers, and RRP motor air coolers. If degradation is found, then an evaluation will be performed to evaluate its effects on the heat exchanger's design functions including its ability to withstand a seismic event. The staff determines that the preventive actions program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.3. In the LRA, this AMP is credited with managing the aging effect of loss of material on the pressure boundary intended function for the components for which this AMP is credited. On this basis, the staff finds that management of loss of material wear in the RCICS is acceptable.In LRA Table 3.2.2-5, the applicant proposed to manage loss of material of carbon steel andstainless steel materials for component types of bolting exposed to an air-indoor (external) andair-outdoor (external) environment using the System Walkdown Program.During the audit and review, the staff asked the applicant to clarify the basis for using the SystemWalkdown Program to manage aging of carbon steel and stainless steel bolting instead of the recommended GALL AMP XI.M18, "Bolting Integrity." By a letter dated July 6, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18. By a letter dated October 17, 2006, the applicant revised its LRA to include a discussion of the Bolting Integrity Program in LRA Section B.1.31. The staff's evaluation of the applicant's System Walkdown Program and Bolting Integrity Program are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff finds that the applicant's Bolting Integrity Program conformed to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 3-2361995 Edition through the 1996 Addenda of ASME Code, Section XI and the applicant's SystemWalkdown Program comprised of inspections of external surfaces of components subject to an AMR. On this basis, the staff finds that the applicant's management of carbon steel and stainless steel bolting, in the RCICS, consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.2.2.3.6  Standby Gas Treatment System Summary of Aging Management Evaluation - LRATable 3.2.2-6The staff reviewed LRA Table 3.2.2-6, which summarizes the results of AMR evaluations for theSGTS component groups.In LRA Table 3.2.2-6, the applicant proposed to manage loss of material of carbon steel materialsfor component types of bolting exposed to an air-indoor (external) environment using the System Walkdown Program.During the audit and review, the staff asked the applicant to clarify the basis for using the SystemWalkdown Program to manage aging of carbon steel bolting instead of the recommended GALL AMP XI.M18, "Bolting Integrity." By a letter dated July 6, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18l. By a letter dated October 17, 2006, the applicant revised its LRA to include a discussion of the Bolting Integrity Program in LRA Section B.1.31. The staff's evaluation of the applicant's System Walkdown Program and Bolting Integrity Program are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff finds that the applicant's Bolting Integrity Program conformed to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI and the applicant's System Walkdown Program comprised of inspections of external surfaces of components subject to an AMR. On this basis, the staff finds that the applicant's management of carbon steel bolting, in the SGTS, consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.2.2.3.7  Primary Containment Penetrations Summary of Aging Management Evaluation - LRATable 3.2.2-7The staff reviewed LRA Table 3.2.2-7, which summarizes the results of AMR evaluations for theprimary containment penetrations component groups.
3-237In LRA Table 3.2.2-7, the applicant proposed to manage loss of material of carbon steel materialsfor component types of piping and valve body exposed to an untreated water environment using the Containment Leak Rate Program.The staff's evaluation of the applicant's Containment Leak Rate Program and is documented inSER Section 3.0.3.2.8. The containment leak rate tests are required to assure that: (a) leakage through primary reactor containment and systems and components penetrating primary containment shall not exceed allowable values specified in technical specifications or associatedbases and (b) periodic surveillance of reactor containment penetrations and isolation valves is performed so that proper maintenance and repairs are made during the service life of containment, and systems and components penetrating primary containment. As documented in the Audit and Review Report, the Containment Leak Rate Program is supplemented by the Containment Inservice Inspection Program, which performs inspections of containment including the penetrations. The staff finds that the aging effect of loss of material of carbon steel material exposed to an untreated water environment is effectively managed using the Containment Leak Rate Program. On this basis, the staff finds that management of loss of material in the primary containment penetrations is acceptable.In LRA Table 3.2.2-7, the applicant proposed to manage loss of material of carbon steel materialsfor component types of bolting exposed to an air-indoor (external) environment using the System Walkdown Program.During the audit and review, the staff asked the applicant to clarify the basis for using the SystemWalkdown Program to manage aging of carbon steel bolting instead of the recommended GALL AMP XI.M18, "Bolting Integrity." By a letter dated July 6, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18. By a letter dated October 17, 2006, the applicant revised its LRA to include a discussion of the Bolting Integrity Program in LRA Section B.1.31.The staff's evaluation of the applicant's System Walkdown Program and Bolting Integrity Program are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff finds that the applicant's management of carbon steel bolting, in the primary containment penetrations, consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.2.2.3.8  Aging Effects/Mechanisms Not Applicable at VYNPS - LRA Table 3.2.1 The staff reviewed LRA Table 3.2.1, which provides a summary of aging managementevaluations for the ESF systems evaluated in the GALL Report.In LRA Table 3.2.1, Item 3.2.1-20, the applicant stated that loss of fracture toughness of CASSpiping, piping components, and piping elements exposed to treated water (borated or unborated)greater than250C (482F) due to thermal aging embrittlement is not applicable at VYNPS.
3-238The staff reviewed, in the LRA and supporting documents, the ESF systems for any CASS piping,piping components, and piping elements exposed to treated water (borated or unborated) greater than 250C (482F), that have loss of fracture toughness due to thermal aging embrittlement.The staff determines that the loss of fracture toughness of CASS piping, piping components, and piping elements exposed to treated water is not applicable at VYNPS. On the basis that there are no CASS piping, piping components, and piping elements exposed to treated water in the ESFsystems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this component type.In LRA Table 3.2.1, Item 3.2.1-21, the applicant stated that cracking of high-strength steel closurebolting exposed to air with steam or water leakage due to cyclic loading and SCC is not applicable at VYNPS.The staff reviewed, in the LRA and supporting documents, the ESF systems for any high-strengthsteel closure bolting exposed to air with steam or water leakage due to cyclic loading. The staffdetermines that cracking of high-strength steel closure bolting exposed to air with steam or water leakage due to cyclic loading and SCC is not applicable at VYNPS. On the basis that there are no high-strength steel closure bolting in the ESF systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this component type.In LRA Table 3.2.1, Item 3.2.1-22, the applicant stated that loss of material of steel closurebolting exposed to air with steam or water leakage due to general corrosion is not applicable at VYNPS. However, by letter dated January 4, 2007, the applicant providing additional clarification stating that its Bolting Integrity Program applies to all bolting exposed to air. The staff reviewed the applicant's January 4, 2007 letter and determined that loss of material ofsteel closure bolting is managed by Bolting Integrity Program and consistent with the GALL Report recommendation. On this basis, the staff finds this acceptable.In LRA Table 3.2.1, Item 3.2.1-26, the applicant stated that loss of material of steel piping, pipingcomponents, and piping elements exposed to closed cycle cooling water due to general, pitting,and crevice corrosion is not applicable at VYNPS. Steel containment isolation components exposed to closed cycle cooling water are all part of other safety systems that are evaluated separately.The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of materialof steel piping, piping components, and piping elements exposed to closed cycle cooling waterdue to general, pitting, and crevice corrosion. The staff finds that the loss of material of steel piping, piping components, and piping elements exposed to closed cycle cooling water due togeneral, pitting, and crevice corrosion is not applicable to VYNPS. On the basis that there are no steel piping, piping components, and piping elements in the ESF systems at VYNPS, the stafffinds that this aging effect is not applicable to VYNPS for this component type.In LRA Table 3.2.1, Item 3.2.1-29, the applicant stated that the loss of material of copper alloypiping, piping components, piping elements, and heat exchanger components exposed to closedcycle cooling water due to pitting, crevice, and galvanic corrosion is not applicable at VYNPS.
There are no copper alloy components exposed to closed cycle cooling water in the ESF system.
3-239The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of materialof copper alloy piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water due to pitting, crevice, and galvanic corrosion. The staff that the loss of material of copper alloy piping, piping components, piping elements, and heatexchanger components exposed to closed cycle cooling water due to pitting, crevice, and galvanic corrosion is not applicable to VYNPS. On the basis that there are no copper alloy piping, piping components, piping elements, and heat exchanger components exposed to closed cyclecooling water in the ESF systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this component type.In LRA Table 3.2.1, Item 3.2.1-33, the applicant stated that the loss of material of steelencapsulation components exposed to air-indoor uncontrolled (internal) due to general, pitting,and crevice corrosion is not applicable at VYNPS. There are no steel encapsulation components in the ESF system.The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of materialof steel encapsulation components exposed to air-indoor uncontrolled (internal) due to general,pitting, and crevice corrosion. The staff finds that the loss of material of steel encapsulation components exposed to air-indoor uncontrolled (internal) due to general, pitting, and crevice corrosion is not applicable to VYNPS. On the basis that there are no steel encapsulation components in the ESF systems at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS.In LRA Table 3.2.1, Item 3.2.1-38, the applicant stated that the loss of material of stainless steelcontainment isolation piping and components internal surfaces exposed to raw water due to pitting, crevice, and MIC, and fouling is not applicable at VYNPS. There are no stainless steel containment isolation piping and components internal surfaces exposed to raw water in the ESF system.The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of materialof stainless steel containment isolation piping and components internal surfaces exposed to rawwater due to pitting, crevice, and MIC, and fouling. The staff finds that the loss of material of stainless steel containment isolation piping and components internal surfaces exposed to rawwater due to pitting, crevice, and MIC, and fouling is not applicable to VYNPS. On the basis that there are no stainless steel containment isolation piping and components internal surfacesexposed to raw water in the ESF systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this component type.In LRA Table 3.2.1, Item 3.2.1-41, the applicant stated that loss of material of copperalloy greater than 15 percent zinc piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water due to selective leaching is not applicable at VYNPS.The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of materialof copper alloy greater than15 percent Zinc piping, piping components, piping elements, and heatexchanger components exposed to closed cycle cooling water due to selective leaching. The staff finds that the loss of material of copper alloy greater than 15 percent zinc piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling 3-240water due to selective leaching is not applicable to VYNPS. On the basis that there are no copperalloy greater than 15 percent zinc piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water in the ESF systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this component type.In LRA Table 3.2.1, Item 3.2.1-43, the applicant stated that loss of material of gray cast ironpiping, piping components, and piping elements exposed to soil due to selective leaching is notapplicable at VYNPS. There are no gray cast iron piping, piping components, and piping elements exposed to soil in the ESF system. The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of materialof gray cast iron piping, piping components, and piping elements exposed to soil due to selective leaching. The staff finds that the loss of material of gray cast iron piping, piping components, andpiping elements exposed to soil due to selective leaching is not applicable to VYNPS. On the basis that there are no gray cast iron piping, piping components, and piping elements exposed tosoil in the ESF systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this component type. 3.2.2.3.9  Engineered Safety Features Systems AMR Line Items With No Aging Effects (LRATables 3.2.2-1 through 3.2.2-7)In LRA Tables 3.2.2-1 through 3.2.2-7, the applicant identified AMR line items where no agingeffects were identified as a result of its AMR. Specifically, instances in which the applicant states that no aging effects were identified occurred with components fabricated from aluminum, copper alloy, fiberglass, and stainless steel material exposed to air indoor (internal/external), air outdoor(external), and sand/concrete environment. The GALL Report states that steel, copper and stainless steel in an environment of plant air indoor (external), are not subject to any aging mechanisms. The staff reviewed LRA Tables 3.2.2-1 through 3.2.2-7 and concludes that the applicant'sanalysis of the material and environment combinations will allow components fabricated of these materials, in these environments, that are within the scope of license renewal, to perform their intended function during the period of extended operation. No aging effects are considered to be applicable to components fabricated from aluminum, copper alloy, fiberglass, and stainless steel material exposed to air indoor (internal/external), air outdoor (external) and sand/concrete environment. Copper alloy, aluminum, and stainless steel components are highly resistant to corrosion in dryatmospheres in the absence of corrosive species, as cited in the American Society for Metals International Metals Handbook, Ninth Edition, Volume 13, the staff has accepted the position that stainless steel in an indoor (internal/external) environment and copper alloy and aluminum in anindoor (internal/external) and sand/concrete environments exhibit no aging effects. The staff concludes that the component or structure will therefore remain capable of performing its intended functions consistent with the CLB for the period of extended operation.
3-241On the basis of its review, the staff finds that the applicant appropriately evaluated the AMRresults involving material, environment, AERM, and AMP combinations that are not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.2.3  ConclusionThe staff concludes that the applicant has provided sufficient information to demonstrate that theeffects of aging for the ESF systems components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3  Aging Management of Auxiliary SystemsThis section of the SER documents the staff's review of the applicant's AMR results for the auxiliary systems components and component groups of:
* standby liquid control system
* service water systems
* reactor building closed cooling water system
* emergency diesel generator system
* fuel pool cooling systems
* fuel oil system
* instrument air system
* fire protection-water system
* fire protection-carbon dioxide system
* heating, ventilation, and air conditioning systems
* primary containment atmosphere control and containment atmosphere dilution systems
* John Deere diesel
* miscellaneous systems in-scope for 10 CFR 54.4(a)(2)3.3.1  Summary of Technical Information in the ApplicationLRA Section 3.3 provides AMR results for the auxiliary systems components and componentgroups. LRA Table 3.3.1, "Summary of Aging Management Evaluations for the Auxiliary Systems Evaluated in Chapter VII of NUREG-1801," is a summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the auxiliary systems components and component groups.The applicant's AMRs evaluated and incorporated applicable plant-specific and industry operatingexperience in the determination of AERMs. The plant-specific evaluation included reviews of condition reports and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.
3-2423.3.2  Staff EvaluationThe staff reviewed LRA Section 3.3 to determine whether the applicant provided sufficientinformation to demonstrate that the effects of aging for the auxiliary systems components that are within the scope of license renewal and subject to an AMR will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).The staff performed an onsite audit of AMRs to ensure the applicant's claim that certain AMRswere consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's audit evaluation are documented in SER Section 3.3.2.1.In the onsite audit, the staff also selected AMRs that were consistent with the GALL Report andfor which further evaluation is recommended. The staff confirmed that the applicant's further evaluations were consistent with the SRP-LR Section 3.3.2.2 acceptance criteria. The staff's audit evaluations are documented in SER Section 3.3.2.2.In the onsite audit, the staff also conducted a technical review of the remaining AMRs that werenot consistent with, or not addressed in, the GALL Report. The technical review evaluated whether all plausible aging effects have been identified and whether the aging effects listed were appropriate for the material-environment combinations specified. The staff's evaluations are documented in SER Section 3.3.2.3.Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensurethat they provided an adequate description of the programs credited with managing or monitoring aging for the auxiliary systems components.For SSCs which the applicant claimed were not applicable or required no aging management, thestaff reviewed the AMR line items and the plant's operating experience to verify the applicant's
 
claims.Table 3.3-1 summarizes the staff's evaluation of components, aging effects/mechanisms, andAMPs, listed in LRA Section 3.3 and addressed in the GALL Report.
3-243Table 3.3-1  Staff Evaluation for Auxiliary System Components in the GALL Report ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation Steel cranes -
structural girders exposed to air -
 
indoor uncontrolled (external)
 
(3.3.1-1)Cumulative fatigue damageTLAA to beevaluated for
 
structural girders of
 
cranes. See the Standard Review
 
Plan, Section 4.7 for
 
generic guidance for
 
meeting the
 
requirements of 10 CFR 54.21(c)(1).NoneThis line item was not used. Steel
 
cranes are evaluated as structural
 
components in SER
 
Section 3.5.
Steel and stainless steel
 
piping, piping
 
components, piping elements, and heat exchanger components exposed to air -
 
indoor uncontrolled, treated borated water or treated water (3.3.1-2)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)NoneFatigue is a TLAA.(See SER Section 3.3.2.2.1)
Stainless steelheat exchanger tubes exposed to treated water
 
(3.3.1-3)Reduction of heat transfer due to
 
foulingWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection
 
Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See SER
 
Sections 3.3.2.1.1
 
and 3.3.2.2.2)
Stainless steel piping, piping
 
components, and
 
piping elements exposed to
 
sodium pentaborate
 
solution > 60C (> 140F)(3.3.1-4)Cracking due to SCCWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection
 
Program (B.1.21)Not applicable.(See SER Section 3.3.2.2.3)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-244 Stainless steel and stainless clad
 
steel heat exchanger components exposed to treated water > 60C (> 140F)(3.3.1-5)Cracking due to SCCPlant-specificWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection
 
Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See SER
 
Sections 3.3.2.1.2
 
and 3.3.2.2.3)
Stainless steel diesel engine exhaust piping, piping components, and
 
piping elements exposed to diesel exhaust (3.3.1-6)Cracking due to SCCPlant-specificPeriodic Surveillanceand Preventive Maintenance Program (B.1.22)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.3 and
 
3.3.2.2.3)
Stainless steelnon-regenerative heat exchanger
 
components exposed to treated borated water
 
> 60C (> 140F)(3.3.1-7)Cracking due toSCC and cyclic
 
loadingWater Chemistry and a plant-specific verification program.
 
An acceptable verification program
 
is to include
 
temperature and radioactivity
 
monitoring of the shell side water, and eddy current testing
 
of tubes.NoneNot applicable toBWRs (See SER Section 3.3.2.2.4)
Stainless steelregenerative heat exchanger components exposed to treated borated water
 
> 60C (> 140F)(3.3.1-8)Cracking due toSCC and cyclic
 
loadingWater Chemistry and a plant-specific verification program.
The AMP is to be
 
augmented by verifying the
 
absence of cracking due to SCC and cyclic loading. A
 
plant-specific AMP is to be evaluated.NoneNot applicable toBWRs (See SER Section 3.3.2.2.4)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-245 Stainless steel high-pressure
 
pump casing in PWR chemical and volume control system
 
(3.3.1-9)Cracking due toSCC and cyclic
 
loadingWater Chemistry and a plant-specific verification program.
The AMP is to be
 
augmented by verifying the
 
absence of cracking due to SCC and cyclic loading. A
 
plant-specific AMP is to be evaluated.NoneNot applicable toBWRs (See SER Section 3.3.2.2.4)High-strength steel closure bolting exposed to air with steam or water leakage.
 
(3.3.1-10)Cracking due toSCC, cyclic loadingBolting Integrity The AMP is to be
 
augmented by
 
appropriate
 
inspection to detect
 
cracking if the bolts are not otherwise
 
replaced during
 
maintenance.NoneNot applicable.(High-strength steel
 
bolting is not used in the auxiliary systems.)Elastomer seals and components exposed to
 
air-indoor
 
uncontrolled (internal/external)
 
(3.3.1-11)Hardening and loss of strength due to
 
elastomer degradationPlant-specific Periodic Surveillanceand Preventive Maintenance
 
Program (B.1.22)Consistent withGALL Report, which
 
recommends further evaluation (See SER
 
Sections 3.3.2.1.4
 
and 3.3.2.2.5)
Elastomer liningexposed to treated water or treated borated water
 
(3.3.1-12)Hardening and loss of strength due to
 
elastomer degradation A plant-specificAMP that determines and
 
assesses the
 
qualified life of the
 
linings in the environment is to be evaluated.NoneNot applicable (See SER Section 3.3.2.2.5)
Boral, boron steel spent fuel storage racks neutron-absorbing sheets exposed to treated water or
 
treated borated water (3.3.1-13)Reduction of neutron-absorbing capacity and loss of
 
material due to
 
general corrosionPlant-specificWater ChemistryControl-BWR Program (B.1.30.2); One-Time
 
Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See SER
 
Sections 3.3.2.1.5
 
and 3.3.2.2.6)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-246 Steel piping, piping component, and piping elements exposed
 
to lubricating oil
 
(3.3.1-14)
Loss of material due to general, pitting, and crevice corrosionLubricating OilAnalysis and One-Time InspectionOil Analysis Program(B.1.20); One-Time
 
Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See SER
 
Sections 3.3.2.1.6
 
and 3.3.2.2.7)
Steel reactor coolant pump oil collection system
 
piping, tubing, and valve bodies exposed to
 
lubricating oil
 
(3.3.1-15)
Loss of material due to general, pitting, and crevice corrosionLubricating OilAnalysis and One-Time InspectionNoneNot applicable (See SER Section 3.3.2.2.7)
Steel reactor coolant pump oil collection system tank exposed to
 
lubricating oil
 
(3.3.1-16)
Loss of material due to general, pitting, and crevice corrosionLubricating OilAnalysis and One-Time Inspection to evaluate the
 
thickness of the lower portion of the
 
tankNoneNot applicable (See SER Section 3.3.2.2.7)
Steel piping, piping components, and
 
piping elements exposed to treated water (3.3.1-17)
Loss of material due to general, pitting, and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection
 
Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See SER
 
Sections 3.3.2.1.7
 
and 3.3.2.2.7)
Stainless steel and steel diesel engine exhaust
 
piping, piping
 
components, and
 
piping elements exposed to diesel exhaust (3.3.1-18)
Loss of material/general (steel only), pitting and crevice corrosionPlant-specificPeriodic Surveillanceand Preventive Maintenance Program (B.1.22); Fire
 
Protection Program (B.1.12.1)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.8 and
 
3.3.2.2.7)Steel (with orwithout coating or wrapping) piping, piping components, and
 
piping elements exposed to soil
 
(3.3.1-19)
Loss of material due to general, pitting, crevice, and MIC Buried Piping andTanks Surveillance
 
or Buried Piping and Tanks Inspection Buried Piping Inspection Program (B.1.1)Consistent withGALL Report, which
 
recommends further evaluation (See SER
 
Section 3.3.2.2.8)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-247 Steel piping, piping components, piping elements, and tanks exposed to fuel oil
 
(3.3.1-20)
Loss of material due to general, pitting, crevice, and MIC, and foulingFuel Oil Chemistryand One-Time
 
InspectionDiesel Fuel Monitoring Program (B.1.9);
One-Time Inspection
 
Program (B.1.21)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.9 and
 
3.3.2.2.9)
Steel heatexchanger components exposed to
 
lubricating oil
 
(3.3.1-21)
Loss of material due to general, pitting, crevice, and MIC, and foulingLubricating OilAnalysis and One-Time InspectionOil Analysis Program (B.1.20);
One-Time Inspection
 
Program (B.1.21)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.10
 
and 3.3.2.2.9)Steel with elastomer lining or
 
stainless steel
 
cladding piping, piping components, and
 
piping elements exposed to treated water and treated borated water
 
(3.3.1-22)
Loss of material dueto pitting and crevice corrosion (only for
 
steel after
 
lining/cladding
 
degradation)Water Chemistryand One-Time
 
InspectionNoneNot applicable (See SER Section 3.3.2.2.10)
Stainless steeland steel with
 
stainless steel
 
cladding heat exchanger components exposed to treated water (3.3.1-23)
Loss of material dueto pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR Program (B.1.30.2); One-Time
 
Inspection Program (B.1.21)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.11
 
and 3.3.2.2.10)
Stainless steel and aluminum
 
piping, piping
 
components, and
 
piping elements exposed to treated water (3.3.1-24)
Loss of material dueto pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR Program (B.1.30.2); One-Time
 
Inspection Program (B.1.21)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.12
 
and 3.3.2.2.10)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-248Copper alloyHVAC piping, piping components, piping elements exposed to
 
condensation (external)
 
(3.3.1-25)
Loss of material dueto pitting and crevice corrosion A plant-specificAMP is to be evaluated.System Walkdown Program (B.1.28);
Periodic Surveillance and Preventive Maintenance Program (B.1.22); Service Water Integrity
 
Program (B.1.26);
Heat Exchanger Monitoring Program (B.1.14)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.13
 
and 3.3.2.2.10)Copper alloy piping, piping
 
components, and
 
piping elements exposed to
 
lubricating oil
 
(3.3.1-26)
Loss of material dueto pitting and crevice corrosionLubricating OilAnalysis and One-Time InspectionOil Analysis Program(B.1.20); One-Time
 
Inspection Program (B.1.21)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.14
 
and 3.3.2.2.10)
Stainless steelHVAC ducting and aluminum HVAC
 
piping, piping
 
components and
 
piping elements exposed to
 
condensation
 
(3.3.1-27)
Loss of material dueto pitting and crevice corrosion A plant-specificAMP is to be evaluated.System Walkdown Program (B.1.28);
Periodic Surveillance and Preventive Maintenance Program (B.1.22); Service Water Integrity
 
Program (B.1.26)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.15
 
and 3.3.2.2.10)Copper alloy fire protection piping, piping components, and
 
piping elements exposed to
 
condensation (internal)
 
(3.3.1-28)
Loss of material dueto pitting and crevice corrosion A plant-specificAMP is to be evaluated.Periodic Surveillanceand Preventive Maintenance Program (B.1.22); Instrument Air Quality Program (B.1.16)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.16
 
and 3.3.2.2.10)
Stainless steel piping, piping
 
components, and
 
piping elements exposed to soil
 
(3.3.1-29)
Loss of material dueto pitting and crevice corrosion A plant-specificAMP is to be evaluated.
Buried Piping Inspection Program (B.1.1)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.17)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-249 Stainless steel piping, piping
 
components, and
 
piping elements exposed to
 
sodium pentaborate
 
solution (3.3.1-30)
Loss of material dueto pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR Program (B.1.30.2); One-Time
 
Inspection Program (B.1.21)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.18
 
and 3.3.2.2.10)Copper alloy piping, piping
 
components, and
 
piping elements exposed to treated water (3.3.1-31)
Loss of material dueto pitting, crevice, and galvanic corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR Program (B.1.30.2); One-Time
 
Inspection Program (B.1.21)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.19
 
and 3.3.2.2.11)
Stainless steel, aluminum and
 
copper alloy
 
piping, piping
 
components, and
 
piping elements exposed to fuel oil
 
(3.3.1-32)
Loss of material dueto pitting, crevice, and MICFuel Oil Chemistryand One-Time
 
InspectionDiesel Fuel Monitoring Program (B.1.9);
One-Time Inspection
 
Program (B.1.21)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.20
 
and 3.3.2.2.12)
Stainless steel piping, piping
 
components, and
 
piping elements exposed to
 
lubricating oil
 
(3.3.1-33)
Loss of material dueto pitting, crevice, and MICLubricating OilAnalysis and One-Time InspectionOil Analysis Program(B.1.20); One-Time
 
Inspection Program (B.1.21)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Sections 3.3.2.1.21
 
and 3.3.2.2.12)
Elastomer seals and components exposed to air -
 
indoor uncontrolled (internal or external)
(3.3.1-34)
Loss of material dueto WearPlant-specificNoneNot applicable.(See SER Section 3.3.2.2.13)Steel with stainless steel
 
cladding pump casing exposed to
 
treated borated water (3.3.1-35)
Loss of material due to cladding breach A plant-specificAMP is to be evaluated.
Reference NRC IN 94-63, "Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks."NoneNot applicable toBWRs ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-250Boraflex spent fuel storage racks
 
neutron-absorbing sheets exposed to treated water
 
(3.3.1-36)Reduction of neutron-absorbing capacity due to boraflex degradationBoraflex MonitoringNoneNot applicable.(Boraflex is not used in the VYNPS spent
 
fuel storage racks.)
Stainless steel piping, piping
 
components, and
 
piping elements exposed to treated water > 60C (> 140F)(3.3.1-37)Cracking due to SCC, IGSCCBWR Reactor WaterCleanup SystemWater ChemistryControl-BWR Program (B.1.30.2); One-Time
 
Inspection Program (B.1.21)Consistent with theGALL Report.
(See SER Section 3.3.2.1.22)
Stainless steel piping, piping
 
components, and
 
piping elements exposed to treated water > 60C (> 140F)(3.3.1-38)Cracking due to SCCBWR StressCorrosion Cracking and Water ChemistryWater ChemistryControl-BWR Program (B.1.30.2); One-Time
 
Inspection Program (B.1.21)Consistent with theGALL Report.
(See SER Section 3.3.2.1.23)
Stainless steelBWR spent fuel
 
storage racks exposed to treated water > 60C (> 140F)(3.3.1-39)Cracking due to SCCWater ChemistryNoneNot applicable.There are no
 
stainless steel spent
 
fuel storage components with
 
intended functions exposed to treated water >60C (>140F).)Steel tanks in diesel fuel oil system exposed
 
to air-outdoor (external)
 
(3.3.1-40)
Loss of material due to general, pitting, and crevice corrosionAboveground SteelTanksSystem Walkdown Program (B.1.28)Consistent with theGALL Report.
(See SER Section 3.3.2.1.24)High-strength steel closure bolting exposed to air with steam or water leakage
 
(3.3.1-41)Cracking due tocyclic loading, SCCBolting IntegrityNoneNot applicable.(High-strength steel
 
closure bolting is not used in the auxiliary systems.)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-251 Steel closurebolting exposed to air with steam or water leakage
 
(3.3.1-42)
Loss of material due to general corrosionBolting IntegrityNoneThis line item was not used. Loss of material
 
of steel closure bolting was addressed by
 
other line items
 
including 3.3.1-43, 3.3.1-55 and 3.3.1-58.
Steel bolting and closure bolting exposed to
 
air-indoor
 
uncontrolled (external) or
 
air-outdoor (External)
 
(3.3.1-43)
Loss of material due to general, pitting, and crevice corrosionBolting IntegrityBolting Integrity Program (B.1.31)Consistent with theGALL Report.
(See SER Section 3.3.2.1.25)Steel compressedair system closure bolting exposed to
 
condensation
 
(3.3.1-44)
Loss of material due to general, pitting, and crevice corrosionBolting IntegrityBolting Integrity Program (B.1.31)Consistent with theGALL Report.
(See SER Section 3.3.2.1.25)
Steel closurebolting exposed to
 
air-indoor
 
uncontrolled (external)
 
(3.3.1-45)
Loss of preload due to thermal effects, gasket creep, and
 
self-looseningBolting IntegrityBolting Integrity Program (B.1.31)Consistent with theGALL Report.
(See Section 3.3.2.1.25)
Stainless steel and stainless clad
 
steel piping, piping
 
components, piping elements, and heat exchanger components exposed to closed cycle cooling water > 60C (> 140F)(3.3.1-46)Cracking due to SCCClosed-CycleCooling Water SystemWater ChemistryControl-Closed Cooling Water
 
Program (B.1.30.3);
One-Time Inspection
 
Program (B.1.21)Consistent with theGALL Report.
(See SER Section 3.3.2.1.26)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-252 Steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to closed cycle cooling water (3.3.1-47)
Loss of material due to general, pitting, and crevice corrosionClosed-CycleCooling Water SystemWater ChemistryControl-Closed Cooling Water
 
Program (B.1.30.3);
Water Chemistry Control-Auxiliary Systems Program (B.1.30.1); One-Time
 
Inspection Program (B.1.21)Consistent with theGALL Report.
(See SER Section 3.3.2.1.27)
Steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to closed cycle cooling water (3.3.1-48)
Loss of material due to general, pitting, crevice, and galvanic corrosionClosed-CycleCooling Water SystemWater ChemistryControl-Closed Cooling Water
 
Program (B.1.30.3);
One-Time Inspection
 
Program (B.1.21)Consistent with theGALL Report.
(See SER Section 3.3.2.1.28)
Stainless steel;steel with
 
stainless steel
 
cladding heat exchanger components exposed to closed cycle cooling water (3.3.1-49)
Loss of material dueto MICClosed-CycleCooling Water SystemWater ChemistryControl-Closed Cooling Water
 
Program (B.1.30.3);
One-Time Inspection
 
Program (B.1.21)Consistent with theGALL Report.
(See SER Section 3.3.2.1.29)
Stainless steel piping, piping
 
components, and
 
piping elements exposed to closed cycle cooling water (3.3.1-50)
Loss of material dueto pitting and crevice corrosionClosed-CycleCooling Water SystemWater ChemistryControl-Closed Cooling Water
 
Program (B.1.30.3);
Water Chemistry Control-Auxiliary Systems Program (B.1.30.1); One-Time
 
Inspection Program (B.1.21)Consistent with theGALL Report.
(See SER Section 3.3.2.1.30)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-253Copper alloy piping, piping
 
components, piping elements, and heat exchanger components exposed to closed cycle cooling water (3.3.1-51)
Loss of material dueto pitting, crevice, and galvanic corrosionClosed-CycleCooling Water SystemWater ChemistryControl-Closed Cooling Water
 
Program (B.1.30.3);
Water Chemistry Control-Auxiliary Systems Program (B.1.30.1); One-Time
 
Inspection Program (B.1.21)Consistent with theGALL Report.
(See SER Section 3.3.2.1.31)
Steel, stainless steel, and copper alloy heat exchanger tubes exposed to closed cycle cooling water (3.3.1-52)Reduction of heat transfer due to
 
foulingClosed-CycleCooling Water SystemWater ChemistryControl-Closed Cooling Water
 
Program (B.1.30.3);
One-Time Inspection
 
Program (B.1.21)Consistent with theGALL Report.
(See SER Section 3.3.2.1.32)Steel compressedair system piping, piping components, and
 
piping elements exposed to
 
condensation (internal)
 
(3.3.1-53)
Loss of material due to general and
 
pitting corrosionCompressed AirMonitoringInstrument Air Quality Program (B.1.16)Consistent with theGALL Report.
(See SER Section 3.3.2.1.33)
Stainless steel compressed air system piping, piping components, and
 
piping elements exposed to
 
internal condensation
 
(3.3.1-54)
Loss of material dueto pitting and crevice corrosionCompressed AirMonitoringInstrument Air Quality Program (B.1.16)Consistent with theGALL Report.
(See SER Section 3.3.2.1.34)
Steel ducting closure bolting exposed to air -
 
indoor uncontrolled (external)
 
(3.3.1-55)
Loss of material due to general corrosionExternal SurfacesMonitoringSystem Walkdown Program (B.1.28)Consistent with theGALL Report.
(See SER Section 3.3.2.1)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-254 Steel HVAC ducting and
 
components external surfaces exposed to air -
 
indoor uncontrolled (external)
 
(3.3.1-56)
Loss of material due to general corrosionExternal SurfacesMonitoringSystem Walkdown Program (B.1.28)Consistent with theGALL Report.
(See SER Section 3.3.2.1)
Steel piping and components external surfaces exposed to air -
 
indoor uncontrolled (External)
 
(3.3.1-57)
Loss of material due to general corrosionExternal SurfacesMonitoringSystem Walkdown Program (B.1.28)Consistent with theGALL Report.
(See SER Section 3.3.2.1)Steel externalsurfaces exposed
 
to air-indoor
 
uncontrolled (external),
air-outdoor (external), and
 
condensation (external)
 
(3.3.1-58)
Loss of material due to general corrosionExternal SurfacesMonitoringSystem Walkdown Program (B.1.28)Consistent with theGALL Report.
(See SER Section 3.3.2.1)
Steel heatexchanger components exposed to
 
air-indoor
 
uncontrolled (external) or
 
air-outdoor (external)
(3.3.1-59)
Loss of material due to general, pitting, and crevice corrosionExternal SurfacesMonitoringSystem Walkdown Program (B.1.28)Consistent with theGALL Report.
(See SER Section 3.3.2.1)
Steel piping, piping components, and
 
piping elements exposed to
 
air-outdoor (external)
 
(3.3.1-60)
Loss of material due to general, pitting, and crevice corrosionExternal SurfacesMonitoringSystem Walkdown Program (B.1.28)Consistent with theGALL Report.
(See SER Section 3.3.2.1)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-255 Elastomer fire barrier penetration seals exposed to
 
air-outdoor or
 
air-indoor
 
uncontrolled
 
(3.3.1-61)
Increased hardness, shrinkage and loss
 
of strength due to weatheringFire ProtectionFire Protection Program (B.1.12.1)Consistent with theGALL Report.
(See SER Section 3.3.2.1.35)
Aluminum piping, piping components, and
 
piping elements exposed to raw water (3.3.1-62)
Loss of material dueto pitting and crevice corrosionFire ProtectionNoneNot applicable.(There are no
 
aluminum components with
 
intended functions exposed to raw water in the auxiliary systems.)Steel fire rateddoors exposed to
 
air-outdoor or
 
air-indoor
 
uncontrolled
 
(3.3.1-63)
Loss of material dueto WearFire ProtectionFire Protection Program (B.1.12.1)Consistent with theGALL Report.
(See SER Section 3.3.2.1.36)
Steel piping, piping components, and
 
piping elements exposed to fuel oil
 
(3.3.1-64)
Loss of material due to general, pitting, and crevice corrosion Fire Protection andFuel Oil ChemistryNoneThis line item was not used. Loss of
 
material of steel
 
components exposed to fuel oil was addressed by
 
other line items
 
including 3.3.1-20
 
and 3.3.1-32.Reinforced concrete structural fire barriers-walls, ceilings and floors exposed to
 
air-indoor
 
uncontrolled
 
(3.3.1-65)Concrete cracking and spalling due to aggressive chemical
 
attack, and reaction with aggregates Fire Protection and Structures Monitoring ProgramNoneThis line item wasnot used. Reinforced concrete structural
 
fire barriers are evaluated as structural
 
components in SER
 
Section 3.5.Reinforced concrete structural fire barriers-walls, ceilings and floors exposed to
 
air-outdoor
 
(3.3.1-66)Concrete cracking and spalling due to freeze thaw, aggressive chemical
 
attack, and reaction with aggregates Fire Protection and Structures Monitoring ProgramNoneThis line item wasnot used. Reinforced concrete structural
 
fire barriers are evaluated as structural
 
components in SER
 
Section 3.5.
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-256Reinforced concrete structural fire barriers-walls, ceilings and floors exposed to
 
air-outdoor or
 
air-indoor
 
uncontrolled
 
(3.3.1-67)
Loss of material due to corrosion of
 
embedded steel Fire Protection and Structures Monitoring ProgramNoneThis line item wasnot used. Reinforced concrete structural
 
fire barriers are evaluated as structural
 
components in SER
 
Section 3.5.
Steel piping, piping components, and
 
piping elements exposed to raw water (3.3.1-68)
Loss of material due to general, pitting, crevice, and MIC, and foulingFire Water SystemFire Water System Program (B.1.12.2);
Periodic Surveillance and Preventive Maintenance Program (B.1.22); One-Time
 
Inspection Program (B.1.21) Consistent with theGALL Report.
(See SER Section 3.3.2.1.37)
Stainless steel piping, piping
 
components, and
 
piping elements exposed to raw water (3.3.1-69)
Loss of material dueto pitting and crevice
 
corrosion, and
 
foulingFire Water SystemFire Water System Program (B.1.12.2);
 
Fire Protection
 
Program (B.1.12.1)Consistent with theGALL Report.
(See SER Section 3.3.2.1.38)Copper alloy piping, piping
 
components, and
 
piping elements exposed to raw water (3.3.1-70)
Loss of material dueto pitting, crevice, and MIC, and foulingFire Water SystemFire Water System Program (B.1.12.2);
 
Fire Protection
 
Program (B.1.12.1);
Periodic Surveillance and Preventive Maintenance Program (B.1.22)Consistent with theGALL Report.
(See SER Section 3.3.2.1.39)
Steel piping, piping components, and
 
piping elements exposed to moist
 
air or condensation (Internal)
 
(3.3.1-71)
Loss of material due to general, pitting, and crevice corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting ComponentsPeriodic Surveillanceand Preventive Maintenance Program (B.1.22)Consistent with theGALL Report.
(See SER Section 3.3.2.1.40)
Steel HVAC ducting and
 
components
 
internal surfaces exposed to
 
condensation (Internal)
 
(3.3.1-72)
Loss of material due to general, pitting, crevice, and (for drip
 
pans and drain lines)
MIC Inspection of Internal Surfaces in Miscellaneous Piping and Ducting ComponentsPeriodic Surveillanceand Preventive Maintenance Program (B.1.22)Consistent with theGALL Report.
(See SER Section 3.3.2.1.41)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-257 Steel crane structural girders
 
in load handling system exposed
 
to air-indoor
 
uncontrolled (external)
 
(3.3.1-73)
Loss of material due to general corrosion Inspection ofOverhead Heavy
 
Load and Light Load (Related to Refueling) Handling SystemsPeriodic Surveillanceand Preventive Maintenance Program (B.1.22); Structures Monitoring Program (B.1.27.2)Consistent with theGALL Report.
(See SER Section 3.3.2.1.42)
Steel cranes - railsexposed to
 
air-indoor
 
uncontrolled (external)
 
(3.3.1-74)
Loss of material dueto Wear Inspection ofOverhead Heavy
 
Load and Light Load (Related to Refueling) Handling SystemsNoneThis line item was not used. Steel crane rails are evaluated as
 
structural components in SER Section 3.5.
Elastomer seals and components exposed to raw water (3.3.1-75)Hardening and loss of strength due to
 
elastomer degradation; loss of
 
material due to
 
erosionOpen-Cycle CoolingWater SystemNoneNot applicable.(There are no
 
elastomeric components exposed to raw or untreated water in the auxiliary systems that require
 
aging management.)
Steel piping, piping components, and
 
piping elements (without lining/
coating or with
 
degraded lining/coating) exposed to raw water (3.3.1-76)
Loss of material due to general, pitting, crevice, and MIC, fouling, and
 
lining/coating
 
degradationOpen-Cycle CoolingWater SystemService WaterIntegrity Program (B.1.26)Consistent with theGALL Report.
(See SER Section 3.3.2.1)
Steel heatexchanger components exposed to raw water (3.3.1-77)
Loss of material due to general, pitting, crevice, galvanic, and MIC, and foulingOpen-Cycle CoolingWater SystemService WaterIntegrity Program (B.1.26); Heat Exchanger Monitoring
 
Program (B.1.14)Consistent with theGALL Report.
(See SER Section 3.3.2.1.43)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-258 Stainless steel,nickel alloy, and
 
copper alloy
 
piping, piping
 
components, and
 
piping elements exposed to raw water (3.3.1-78)
Loss of material dueto pitting and crevice corrosionOpen-Cycle CoolingWater SystemNoneThis line was notused. There are no
 
nickel alloy components exposed to raw water in the auxiliary systems.
 
Stainless steel and
 
copper alloy components exposed to raw water are
 
addressed in other
 
line items including
 
3.3.1-79 and 3.3.1-81.
Stainless steel piping, piping
 
components, and
 
piping elements exposed to raw water (3.3.1-79)
Loss of material dueto pitting and crevice
 
corrosion, and
 
foulingOpen-Cycle CoolingWater SystemService WaterIntegrity Program (B.1.26)Consistent with theGALL Report.
(See SER Section 3.3.2.1)
Stainless steel and copper alloy
 
piping, piping
 
components, and
 
piping elements exposed to raw water (3.3.1-80)
Loss of material dueto pitting, crevice, and MICOpen-Cycle CoolingWater SystemNoneNot applicable.(This line applies to EDG system
 
components. At VYNPS, these
 
components are not exposed to raw water (heat exchanger components exposed to raw water are
 
addressed in Line
 
Item 3.3.1-82).Copper alloy piping, piping
 
components, and
 
piping elements, exposed to raw water (3.3.1-81)
Loss of material dueto pitting, crevice, and MIC, and foulingOpen-Cycle CoolingWater SystemService WaterIntegrity Program (B.1.26)Consistent with theGALL Report.
(See SER Section 3.3.2.1)Copper alloy heatexchanger components exposed to raw water (3.3.1-82)
Loss of material dueto pitting, crevice, galvanic, and MIC, and foulingOpen-Cycle CoolingWater SystemService WaterIntegrity Program (B.1.26)Consistent with theGALL Report.
(See SER Section 3.3.2.1)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-259 Stainless steel and copper alloy heat exchanger tubes exposed to raw water (3.3.1-83)Reduction of heat transfer due to
 
foulingOpen-Cycle CoolingWater SystemService WaterIntegrity Program (B.1.26); Fire
 
Protection Program (B.1.12.1)Consistent with theGALL Report.
(See SER Section 3.3.2.1.44)Copper alloy > 15 percent Zn piping, piping components, piping elements, and heat exchanger components exposed to raw water, treated water, or closed cycle cooling water (3.3.1-84)
Loss of material dueto selective leachingSelective Leachingof MaterialsSelective Leaching Program (B.1.25)Consistent with theGALL Report.
(See SER Section 3.3.2.1)Gray cast iron piping, piping
 
components, and
 
piping elements exposed to soil, raw water, treated water, or closed-cycle cooling water
 
(3.3.1-85)
Loss of material dueto selective leachingSelective Leachingof MaterialsSelective Leaching Program (B.1.25)Consistent with theGALL Report.
(See SER Section 3.3.2.1)
Structural steel(new fuel storage rack assembly) exposed to
 
air-indoor
 
uncontrolled (external)
 
(3.3.1-86)
Loss of material due to general, pitting, and crevice corrosion StructuresMonitoring ProgramNoneThis line item was not used. Structural steel of the new fuel
 
storage rack assembly is evaluated
 
as a structural
 
component in SER
 
Section 3.5.Boraflex spent fuel storage racks
 
neutron-absorbing sheets exposed to
 
treated borated water (3.3.1-87)Reduction of neutron-absorbing capacity due to boraflex degradationBoraflex MonitoringNoneNot applicable toBWRs ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-260 Aluminum andcopper alloy > 15
 
percent Zn piping, piping components, and
 
piping elements exposed to air with borated water
 
leakage (3.3.1-88)
Loss of material due to Boric acid corrosionBoric Acid CorrosionNoneNot applicable toBWRs Steel bolting andexternal surfaces exposed to air with borated water
 
leakage (3.3.1-89)
Loss of material due to Boric acid corrosionBoric Acid CorrosionNoneNot applicable toBWRs Stainless steeland steel with
 
stainless steel
 
cladding piping, piping components, piping elements, tanks, and fuel
 
storage racks exposed to treated borated water
 
> 60C (> 140F)(3.3.1-90)Cracking due to SCCWater ChemistryNoneNot applicable toBWRs Stainless steeland steel with
 
stainless steel
 
cladding piping, piping components, and
 
piping elements exposed to treated borated water
 
(3.3.1-91)
Loss of material dueto pitting and crevice corrosionWater ChemistryNoneNot applicable toBWRsGalvanized steel piping, piping
 
components, and
 
piping elements exposed to
 
air-indoor
 
uncontrolled
 
(3.3.1-92)NoneNoneNoneNot applicable.(Galvanized steel
 
surfaces are evaluated as steel for the auxiliary systems.)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-261Glass pipingelements exposed
 
to air, air-indoor
 
uncontrolled (external), fuel oil, lubricating oil, raw water, treated water, and treated borated water
 
(3.3.1-93)NoneNoneNoneConsistent with theGALL Report.
(See LRA Section 3.3.2.1)
Stainless steel and nickel alloy
 
piping, piping
 
components, and
 
piping elements exposed to
 
air-indoor
 
uncontrolled (external)
 
(3.3.1-94)NoneNoneNoneConsistent withGALL Report.
(See LRA Section 3.3.2.1)
Steel and aluminum piping, piping components, and
 
piping elements exposed to
 
air-indoor
 
controlled (external)
 
(3.3.1-95)NoneNoneNoneNot applicable.(There are no components exposed
 
to controlled indoor air at VYNPS.)
Steel and stainless steel
 
piping, piping
 
components, and
 
piping elements in
 
concrete (3.3.1-96)NoneNoneNoneConsistent with theGALL Report.
(See LRA Section 3.3.2.1)
Steel, stainless steel, aluminum, and copper alloy
 
piping, piping
 
components, and
 
piping elements exposed to gas
 
(3.3.1-97)NoneNoneNoneConsistent with theGALL Report.
(See LRA Section 3.3.2.1)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-262 Steel, stainless steel, and copper alloy piping, piping
 
components, and
 
piping elements exposed to dried
 
air (3.3.1-98)NoneNoneNoneNot applicable.(Dried (treated) air is
 
maintained as an environment as a
 
result of the Instrument Air Quality
 
Program, so aging effects may occur without that program.)
Stainless steel and copper alloy
 
< 15 percent Zn
 
piping, piping
 
components, and
 
piping elements exposed to air with borated water
 
leakage (3.3.1-99)NoneNoneNoneNot applicable toBWRsThe staff's review of the auxiliary systems component groups followed any one of severalapproaches. One approach, documented in SER Section 3.3.2.1, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.3.2.2, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.3.2.3, reviewed AMR results for components that the applicant indicated are not consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the auxiliary systems components is documented in SER Section 3.0.3.3.3.2.1  AMR Results Consistent with the GALL ReportSummary of Technical Information in the Amended Application. LRA Section 3.3.2.1 identifiesthe materials, environments, AERMs, and the following programs that manage aging effects for the auxiliary systems components:
* Buried Piping and Tanks Inspection Program
* Diesel Fuel Monitoring Program
* Fire Protection Program
* Fire Water System Program
* Flow-Accelerated Corrosion Program
* Heat Exchanger Monitoring Program
* Instrument Air Quality Program
* Oil Analysis Program
* One-Time Inspection Program
* Periodic Surveillance and Preventive Maintenance Program 3-263
* Selective Leaching Program
* Service Water Integrity Program
* System Walkdown Program
* Water Chemistry Control - Auxiliary Systems Program
* Water Chemistry Control - BWR Program
* Water Chemistry Control - Closed Cooling Water ProgramStaff Evaluation. LRA Tables 3.3.2-1 through 3.3.2-12 and Tables 3.3.2-13-1 through3.3.2-13-58 summarize AMRs for the auxiliary systems components and indicate AMRs claimed to be consistent with the GALL Report.For component groups evaluated in the GALL Report for which the applicant claimedconsistency with the report and for which it does not recommend further evaluation, the staff's audit and review determined whether the plant-specific components of these GALL Report component groups were bounded by the GALL Report evaluation.The applicant noted for each AMR line item how the information in the tables aligns with theinformation in the GALL Report. The staff audited those AMRs with notes A through E indicating how the AMR is consistent with the GALL Report.Note A indicates that the AMR line item is consistent with the GALL Report for component,material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP.
The staff audited these line items to verify consistency with the GALL Report and validity of the AMR for the site-specific conditions.Note B indicates that the AMR line item is consistent with the GALL Report for component,material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify consistency with the GALL Report and verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also determines whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions.Note C indicates that the component for the AMR line item, although different from, is consistentwith the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified in the GALL Report a different component with the same material, environment, aging effect, and AMP as the component under review. The staff audited these line items to verify consistency with the GALL Report. The staff also determines whether the AMR line item of the different component was applicable to the component under review and whether the AMR was valid for the site-specific conditions.
3-264Note D indicates that the component for the AMR line item, although different from, is consistentwith the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component was applicable to the component under review and whether the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also determines whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions.Note E indicates that the AMR line item is consistent with the GALL Report for material,environment, and aging effect, but credits a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also determines whether the credited AMP would manage the aging effect consistently with the GALL AMP and whether the AMR was valid for the site-specific conditions.The staff audited and reviewed the information in the LRA. The staff did not repeat its review ofthe matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluation follows.3.3.2.1.1  Reduction of Heat Transfer Due to Fouling For reduction of heat transfer due to fouling of stainless steel heat exchanger tubes exposed totreated water, the GALL Report recommends programs consistent with GALL AMP XI.M2, "Water Chemistry" and GALL AMP XI.M32, "One-Time Inspection."In the LRA Table 3.3.1, Item 3.3.1-3, the applicant stated that its Water Chemistry Control-BWRProgram, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage reduction of heat transfer due to fouling in stainless steel heat exchanger tubes exposed to treated water. During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13).
During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-3 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicant's management of the reduction of heat transfer due to fouling in stainless steel heat exchanger tubes exposed to treated water consistent with the GALL Report and therefore acceptable.
3-265On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.2  Cracking Due to Stress Corrosion Cracking For cracking due to SCC of stainless steel and stainless clad steel heat exchanger componentsexposed to treated water greater than 60C (greater than140F), the GALL Report recommendsa plant-specific program.In LRA Table 3.3.1, Item 3.3.1-5, the applicant stated that cracking in stainless steel heatexchanger tubes exposed to treated water greater than140F is managed by the WaterChemistry Control-BWR Program. The One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13).
During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.1.1-5 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicant's management of cracking in stainless steel heat exchanger tubes exposed to treated water greater than 140F consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.3  Cracking Due to Stress Corrosion Cracking For cracking due to SCC of stainless steel diesel engine exhaust piping, piping components, andpiping elements exposed to diesel exhaust, the GALL Report recommends a plant-specific program.In LRA Table 3.3.1, Item 3.3.1-6, the applicant stated that cracking of stainless steel exhaustcomponents will be managed by the Periodic Surveillance and Preventive Maintenance Program.The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program.This evaluation is documented in SER Section 3.0.3.3.5. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for expansion joints exposed to exhaust gas and therefore is acceptable to the staff.
3-266On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.4  Hardening and Loss of Strength Due to Elastomer Degradation For hardening and loss of strength due to elastomer degradation of elastomer seals andcomponents exposed to air-indoor uncontrolled (internal/external), the GALL Report recommends a plant-specific program.In LRA Table 3.3.1, Item 3.3.1-11, the applicant stated that the change in material properties ofelastomer components exposed to indoor air will be managed by the Periodic Surveillance and Preventive Maintenance Program.The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program.This evaluation is documented in SER Section 3.0.3.3.5. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for duct flexible connections in the HVAC system and therefore is acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.5  Reduction of Neutron-Absorbing Capacity and Loss of Material Due to GeneralCorrosionFor reduction of neutron-absorbing capacity and loss of material due to general corrosion ofboral, boron steel spent fuel storage racks neutron-absorbing sheets exposed to treated water or treated borated water, the GALL Report recommends a plant-specific program.In the LRA Table 3.3.1, Item 3.3.1-13, the applicant stated that the Water ChemistryControl-BWR Program manages the degradation of boral.During the audit and review, the staff asked the applicant how a purely preventive program couldaddress this aging effect. The applicant confirmed that where the Water Chemistry Control-BWR Program was applied, including prevention of loss of material from boral, the One-Time Inspection Program would be used to confirm its effectiveness.In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRAis revised to state that the effectiveness of the Water Chemistry Control-BWR Program is confirmed by the One-Time Inspection Program.The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-TimeInspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-BWR Program relies on monitoring and 3-267control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of theOne-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicant's management of the degradation of boral using the combination of these AMPs satisfies the criteria of the SRP-LR Appendix A.1 and is therefore acceptable.On the basis of its review, the staff determines that the applicant, with the change in theapplication identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.6  Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting, and crevice corrosion of steel piping, pipingcomponents, and piping elements exposed to lubricating oil, the GALL Report recommends programs consistent with GALL AMP XI.M39, "Lubricating Oil Analysis," and GALL AMP XI.M32, "One-Time Inspection."In the discussion column of LRA Table 3.3.1, Item 3.3.1-14, the applicant stated that the OilAnalysis Program, manages loss of material in steel components.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program.The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection Program.These evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. With the change discussed above, the applicant is managing the loss of material due to general, pitting, and crevice corrosion of steel piping, piping components, and piping elements exposedto lubricating oil in a manner that is consistent with the GALL Report and therefore acceptable.
In addition, this aging effect is also managed for carbon steel gauges, filter housings, heater housings, pump casings, strainer housings, tanks, gear boxes, and heat exchanger shells as well as gray cast iron valve bodies exposed to lubricating oil.On the basis of its review, the staff determines that the applicant, with the change in theapplication identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.7  Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting, and crevice corrosion of steel piping, pipingcomponents, and piping elements exposed to treated water, the GALL Report recommends programs consistent with GALL AMP XI.M2, "Water Chemistry" and GALL AMP XI.M32, "One-Time Inspection."
3-268In LRA Table 3.3.1, Item 3.3.1-17, the applicant stated that the loss of material in steelcomponents is managed by the Water Chemistry Control - BWR Program. The One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13).
During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.1.1-17 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicant's management of loss of material in steel components consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.8  Loss of Material/General (Steel Only), Pitting and Crevice Corrosion For loss of material/general (steel only), pitting and crevice corrosion of stainless steel and steeldiesel engine exhaust piping, piping components, and piping elements exposed to dieselexhaust, the GALL Report recommends a plant-specific program.In the LRA Table 3.3.1, Item 3.3.1-18, the applicant stated that the Periodic Surveillance andPreventive Maintenance Program and the Fire Protection Program will manage loss of material in steel and stainless steel components exposed to diesel exhaust.The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program.This evaluation is documented in SER Section 3.0.3.3.5. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 and therefore is acceptable.The staff also reviewed the applicant's Fire Protection Program. This evaluation is documentedin SER Section 3.0.3.2.11. This AMP is consistent, with exceptions and enhancements, with GALL AMP XI.M26, "Fire Protection," and the staff therefore finds it to be an acceptable method for management of loss of material from carbon steel expansion joints in the EDG system, stainless steel expansion joints and carbon steel piping, silencers, and turbochargers in theEDG, fire protection-water, and John Deere Diesel systems exposed to diesel exhaust.On the basis of its review, the staff determines that the applicant appropriately addressed theaging effect/mechanism, as recommended by the GALL Report.
3-2693.3.2.1.9  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-InfluencedCorrosion, and FoulingFor loss of material due to general, pitting, crevice, and MIC, and fouling of steel piping, pipingcomponents, piping elements, and tanks exposed to fuel oil, the GALL Report recommends a program consistent with GALL AMP XI.M30, "Fuel Oil Chemistry" and GALL AMP XI.M32, "One-Time Inspection."In LRA Table 3.3.1, Item 3.3.1-20, the applicant stated that the Diesel Fuel Monitoring Programmanages loss of material in steel components.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant amended its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program will verify the effectiveness of the Diesel Fuel Monitoring Program. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-20 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Diesel Fuel Monitoring Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.2.9 and 3.0.3.1.6, respectively. The staff concludes that the applicant's Diesel Fuel Monitoring Program in conjunction with the One-Time Inspection Program provided assurance that the loss of material due to corrosion is adequately managed by monitoring and controlling conditions that would cause this aging effect and by monitoring the effectiveness of the program through surveillance and testing. On this basis, the staff finds that the applicant management of loss of material due to general, pitting, crevice, and MIC, and fouling of steel piping, piping components, piping elements, and tanks exposed to fuel oilconsistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.10  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-InfluencedCorrosion, and FoulingFor loss of material due to general, pitting, crevice, and MIC, and fouling of steel heat exchangercomponents exposed to lubricating oil, the GALL Report recommends programs consistent with GALL AMP XI.M39, "Lubricating Oil Analysis" and GALL AMP XI.M32, "One-Time Inspection."In LRA Table 3.3.1, Item 3.3.1-21, the applicant stated that the Oil Analysis Program managesloss of material in steel heat exchanger components.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant amended its LRA. The applicant stated that LRA is revised to state that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-21 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Oil 3-270Analysis Program and One-Time Inspection Program. These evaluations are documented inSER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. The Oil Analysis Program includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. Operating experience at VYNPS has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion has not and will not affect the intended functions of these components. The Oil Analysis Program will be supplemented by the One-Time Inspection Program to verify its effectiveness. On this basis, the staff finds that the applicant's management of loss of material due to general, pitting, crevice, and MIC, and fouling of steel heat exchanger components exposed to lubricating oil consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.11  Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of stainless steel and steel with stainlesssteel cladding heat exchanger components exposed to treated water, the GALL Report recommends programs consistent with GALL AMP XI.M2, "Water Chemistry" and GALL AMP XI.M32, "One-Time Inspection."In LRA Table 3.3.1, Item 3.3.1-23, the applicant stated that the loss of material in stainless steelheat exchanger components is managed by the Water Chemistry Control-BWR Program. The One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13).
During interviews with the applicant's technical personnel staff, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-23 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicant's management of loss of material in stainless steel heat exchanger components consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
3-2713.3.2.1.12  Loss of Material Due to Pitting and Crevice CorrosionFor loss of material due to pitting and crevice corrosion of stainless steel and aluminum piping,piping components, and piping elements exposed to treated water, the GALL Report recommends programs consistent with GALL AMP XI.M2, "Water Chemistry" and GALL AMP XI.M32, "One-Time Inspection."In LRA Table 3.3.1, Item 3.3.1-24, the applicant stated that the loss of material in stainless steelcomponents is managed by the Water Chemistry Control-BWR Program. The One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13).
During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-24 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicant's management of loss of material in stainless steel components consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.13  Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of copper alloy HVAC piping, pipingcomponents, piping elements exposed to condensation (external), the GALL Report suggests that a plant-specific AMP is to be evaluated.In LRA Table 3.3.1, Item 3.3.1-25, the applicant stated that the System Walkdown Program,Periodic Surveillance and Preventive Maintenance Program, Service Water Integrity Program and the Heat Exchanger Monitoring Program will manage loss of material in copper alloy components.The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion fromcopper-alloy (greater than15 percent zinc) heat exchanger tubes exposed to condensation in the reactor building CCWS is to be managed using the Heat Exchanger Monitoring Program, a plant-specific AMP.The staff's review of the applicant's Heat Exchanger Monitoring Program is documented in SERSection 3.0.3.3.1. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for heat exchanger tubes in the reactor building CCWS and therefore is acceptable.
3-272The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion fromcopper-alloy (less than15 percent zinc) heat exchanger tubes exposed to condensation in the HVAC system is to be managed using the Periodic Surveillance and Preventive Maintenance Program, a plant-specific AMP.The staff's review of the applicant's Periodic Surveillance and Preventive Maintenance Programis documented in SER Section 3.0.3.3.5. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for heat exchanger tubes of the HVAC system and therefore is acceptable.The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion fromcopper-alloy (greater than15 percent zinc) heat exchanger tubes exposed to condensation in the SW and HVAC systems is to be managed using the Service Water Integrity Program.The staff's review of the applicant's Service Water Integrity Program is documented in SERSection 3.0.3.2.16. The program satisfies the criteria of SRP-LR Appendix A.1 for heat exchanger tubes in the SW and HVAC systems and therefore is acceptable.The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion fromcopper-alloy (greater than15 percent zinc) valve bodies in the SWS and HVAC system exposed to condensation is to be managed using the System Walkdown Program.The staff's review of the applicant's System Walkdown Program is documented in SERSection 3.0.3.1.9. The program satisfies the criteria of SRP-LR Appendix A.1 for valve bodies in the SWS and pump casings in the HVAC system exposed to condensation and therefore is acceptable.The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion fromcopper-alloy (less than15 percent zinc) piping, tubing and valve bodies in the SWS; compressor housings and tubing in the HVAC system; and copper-alloy tubing in the CW, CWP, house heating boiler, and RHRSW systems exposed to condensation is to be managed using the System Walkdown Program.The staff's review of the applicant's System Walkdown Program is documented in SERSection 3.0.3.1.9. The program satisfies the criteria of SRP-LR Appendix A.1 for piping, tubing, valve bodies, and compressor housing exposed to condensation in the SW CW, CWP, HB, RHRSW, and HVAC systems and therefore is acceptable.On the basis of its review, the staff determines that the applicant appropriately addressed theaging effect/mechanism, as recommended by the GALL Report.3.3.2.1.14  Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of copper alloy piping, pipingcomponents, and piping elements exposed to lubricating oil, the GALL Report recommends programs consistent with GALL AMP XI.M39, "Lubricating Oil Analysis" and GALL AMP XI.M32, "One-Time Inspection."
3-273In LRA Table 3.3.1, Item 3.3.1-26, the applicant stated that the Oil Analysis Program managesloss of material in copper alloy components.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program.The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection Program.These evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. With the change discussed above, the applicant is managing the loss of material due to pitting and crevice corrosion of copper alloy piping, piping components, and piping elements exposed tolubricating oil in a manner that is consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff determines that the applicant, with the change in theapplication identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.15  Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of stainless steel HVAC ducting andaluminum HVAC piping, piping components and piping elements exposed to condensation, theGALL Report suggests that a plant-specific AMP is to be evaluated.In LRA Table 3.3.1, Item 3.3.1-27, the applicant stated that the System Walkdown Program,Periodic Surveillance and Preventive Maintenance Program, and the Service Water Integrity Program manage loss of material in stainless steel components. The applicant also stated that there are no aluminum pressure boundary components exposed to condensation in the VYNPS auxiliary systems.The staff's evaluations of the applicant's System Walkdown Program, Periodic Surveillance andPreventive Maintenance Program, and the Service Water Integrity Program are documented in SER Sections 3.0.3.1.9, 3.0.3.3.5, and 3.0.3.2.16, respectively. The System Walkdown Program is consistent with program described in GALL AMP XI.M36, "External Surface Monitoring." The Periodic Surveillance and Preventive Maintenance Program includes periodic inspections and tests that manage aging effects not managed by other AMP s. The Service Water Integrity Program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the SWSs will be managed for the period of extended operation. The staff determines that the combination of these AMPs satisfies the criteria of SRP-LR Appendix A.1 for a plant-specific AMP. On these basis, the staff finds that the applicant adequately manage the loss of material due to pitting and crevice corrosion of stainless steel components. The staff alsoreviewed LRA and supporting documents to confirm that there are no aluminum boundary components exposed to condensation in the VYNPS auxiliary systems.The applicant stated that loss of material due to pitting and crevice corrosion from stainless steelpiping, tanks, and valve bodies of the EDG system exposed to untreated air is to be managed using the Periodic Surveillance and Preventive Maintenance Program, a plant-specific AMP.
3-274The staff's evaluation of the applicant's Periodic Surveillance and Preventive MaintenanceProgram is documented in SER Section 3.0.3.3.5. This program includes periodic inspections and tests of the EDG system to manage aging effects. On this basis, the staff finds the loss of material due to pitting and crevice corrosion from steel piping, tanks, and valve bodies of the EDG system adequately managed.The applicant also stated that loss of material due to pitting and crevice corrosion from stainlesssteel suction barrels exposed to condensation in the SWS is to be managed using the Service Water Integrity Program.The staff's evaluation of the applicant's Service Water Integrity Program is documented in SERSection 3.0.3.2.16. The Service Water Integrity Program includes surveillance and control techniques to manage aging effects in the SWS or SCs by the SWS. The program relies on implementation of the recommendation of GL 89-13 to ensure that the effects of aging will be managed. On this basis, the staff finds that loss of material due to pitting and crevice corrosion from stainless steel suction barrels is adequately managed.In addition, the applicant stated loss of material due to pitting and crevice corrosion incondensation from stainless steel piping, tubing, and valve bodies of the RHRSW system as wellas from bolting, expansion joints, indicators, orifices, piping, tubing, thermowells, and valve bodies of the SWS is to be managed using the System Walkdown Program.The staff's evaluation of the applicant's System Walkdown Program is documented in SERSection 3.0.3.1.9. The System Walkdown Program is consistent with the program described in GALL AMP XI.M36, "External Surfaces Monitoring." This program entails inspections of external surfaces of components subject to an AMR. The program is also credited with managing loss of material from internal surfaces where internal and external material-environment combinations are the same and external surface conditions represent internal surface conditions. On this basis, the staff finds that the loss of material due to pitting and crevice corrosion in condensation from stainless steel piping, tubing, and valve bodies of the RHRSW system as well as frombolting, expansion joints, indicators, orifices, piping, tubing, thermowells, and valves bodies of the SWS.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.16  Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of copper alloy fire protection piping,piping components, and piping elements exposed to condensation (internal), the GALL Reportsuggests that a plant-specific AMP is to be evaluated.In LRA Table 3.3.1, Item 3.3.1-28, the applicant stated that the Periodic Surveillance andPreventive Maintenance Program and the Instrument Air Quality Program will manage loss of material in copper alloy components. The applicant also stated that loss of material due to pitting and crevice corrosion from copper alloy tubing and valve bodies of the EDG system exposed to untreated air is to be managed using the Periodic Surveillance and Preventive Maintenance Program, a plant-specific AMP.
3-275The staff's evaluation of the applicant's Periodic Surveillance and Preventive MaintenanceProgram is documented in SER Section 3.0.3.3.5. The staff determines that the applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1, which includes periodic inspections and tests to manage aging effects. On the basis that the components are inspected and tested periodically, staff finds that the of loss of material due to pitting and crevice corrosion from copper alloy tubing and valve will be adequately managed.The applicant also stated that loss of material due to pitting and crevice corrosion fromcopper-alloy valve bodies in the IA system exposed to treated air is to be managed using the Instrument Air Quality Program, a plant-specific AMP.The staff's evaluation of the applicant's Instrument Air Quality Program is documented in SERSection 3.0.3.3.4. The staff determines that the applicant's Instrument Air Quality Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. The program ensures that IA supplied to components is maintained free of water and significant contaminants, thereby preserving an environment that is not conducive to loss of material. On this basis, the staff finds that the applicant's management of the loss of material for copper-alloy components exposed to treated air (internal) using its Instrument Air Quality Program acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, in a manner consistent with the GALL Report.3.3.2.1.17  Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of stainless steel piping, pipingcomponents, and piping elements exposed to soil, the GALL Report recommends that a plant-specific AMP is to be evaluated.In LRA Table 3.3.1, Item 3.3.1-29, the applicant stated that the Buried Piping InspectionProgram, manages loss of material in stainless steel components.The staff reviewed the applicant's Buried Piping Inspection Program and its evaluation isdocumented in SER Section 3.0.3.2.1. The applicant's Buried Piping Inspection Program is consistent, with exceptions and enhancement, with GALL AMP XI.M34, "Buried Piping and Tanks Inspection." The staff concludes that the applicant's Buried Piping Inspection Program provided assurance that the program will manage aging effects on the external surfaces of buried steel piping. On this basis, the staff finds that applicant's management of loss of material in stainless steel components using its Buried Piping Inspection Program acceptable.On the basis of its review, the staff determines that the applicant appropriately addressed theaging effect/mechanism, as recommended by the GALL Report.
3-2763.3.2.1.18  Loss of Material Due to Pitting and Crevice CorrosionFor loss of material due to pitting and crevice corrosion of stainless steel piping, pipingcomponents, and piping elements exposed to sodium pentaborate solution, the GALL Report recommends programs consistent with GALL AMP XI.M2, "Water Chemistry" and GALL AMP XI.M32, "One-Time Inspection."In LRA Table 3.3.1, Item 3.3.1-30, the applicant stated that the loss of material in stainless steelcomponents is managed by the Water Chemistry Control-BWR Program. The One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13).
During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-30 in the population that is subject to the One-Time Inspection Program.
The staff reviewed the applicant's Water Chemistry Control-BWRProgram and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.2.11 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicant's management of loss of material in stainless steel components consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.19  Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion For loss of material due to pitting, crevice, and galvanic corrosion of copper alloy piping, pipingcomponents, and piping elements exposed to treated water, the GALL Report recommends programs consistent with GALL AMP XI.M2, "Water Chemistry" and GALL AMP XI.M32, "One-Time Inspection."In LRA Table 3.3.1, Item 3.3.1-31, the applicant stated that loss of material in copper alloycomponents exposed to treated water is managed by the Water Chemistry Control-BWR Program. The applicant also stated the One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13).
During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-31 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.2.11 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 3-277(BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the WaterChemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicant's management of loss of material in copper alloy components exposed to treated water consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.20  Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion For loss of material due to pitting, crevice, and MIC of stainless steel, aluminum and copper alloypiping, piping components, and piping elements exposed to fuel oil, the GALL Reportrecommends programs consistent with GALL AMP XI.M30, "Fuel Oil Chemistry" and GALL AMP XI.M32, "One-Time Inspection."In LRA Table 3.3.1, Item 3.3.1-32, the applicant stated that the Diesel Fuel Monitoring Programmanages loss of material in stainless steel, aluminum and copper alloy components.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program verifies the effectiveness of the Diesel Fuel Monitoring Program.The staff reviewed the applicant's Diesel Fuel Monitoring Program and One-Time InspectionProgram. These evaluations are documented in SER Sections 3.0.3.2.9 and 3.0.3.1.6, respectively. The staff determines that the applicant's Diesel Fuel Monitoring Program in conjunction with the One-Time Inspection Program provided assurance that loss of material in stainless steel, aluminum and copper alloy components is adequately managed by monitoringand controlling conditions that would cause this aging effect and by monitoring the effectiveness of the program through surveillance and testing. On this basis, the staff finds that the applicant management of loss of material in stainless steel, aluminum and copper alloy components consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff determines that the applicant, with the change in theapplication identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.21  Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion For loss of material due to pitting, crevice, and MIC of stainless steel piping, piping components,and piping elements exposed to lubricating oil, the GALL Report recommends programs consistent with GALL AMP XI.M39, "Lubricating Oil Analysis" and GALL AMP XI.M32, "One-Time Inspection."
3-278In the discussion column of LRA Table 3.3.1, Item 3.3.1-33, the applicant stated that the OilAnalysis Program manages loss of material in stainless steel components.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program.The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection Program.These evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. With the change discussed above, the applicant is managing the loss of material due to pitting, crevice, and MIC of stainless steel piping, piping components, and piping elements exposed tolubricating oil in a manner that is consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff determines that the applicant, with the change in theapplication identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.22  Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking For cracking due to SCC, IGSCC of stainless steel piping, piping components, and pipingelements exposed to treated water greater than 140F, the GALL Report recommends aprogram consistent with GALL AMP XI.M25, "BWR Reactor Water Cleanup System Program."In LRA Table 3.3.1, Item 3.3.1-37, the applicant stated that cracking of stainless steelcomponents of the reactor water cleanup (RWCU) system is managed by the Water Chemistry Control-BWR Program. The applicant also stated the One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program-BWR Program. In addition, the applicant stated that the only components to which this line item applies are included in-scope only in accordance with10 CFR 54.4(a)(2) and listed in the LRA series 3.3.2-13-xx tables. The GALL Report stated that no IGSCC inspection is recommended for plants that have piping made of material that is resistant to IGSCC, and that have satisfactorily completed all actions requested in GL 89-10.During the audit and review, the staff confirmed that VYNPS meets these criteria. The staff findsthat since VYNPS satisfies these criteria, the Water Chemistry Control-BWR Program is an acceptable alternative to GALL AMP XI.M25 to manage cracking. As described in LRA Table 3.3.1, Item 3.3.1-37, the One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program-BWR Program.The staff reviewed the applicant's Water Chemistry Control-BWR Program and its evaluation isdocumented in SER Section 3.0.3.1.11. The staff finds this program to be effective in mitigating cracking due to SCC, IGSCC of stainless steel piping, piping components, and piping elementsexposed to treated water greater than 140F. It is to be combined with the One-Time InspectionProgram to confirm the effectiveness of the Water Chemistry-BWR Program. The staff finds this combination of programs will adequately manage this aging effect and their use is acceptable.
3-279On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.23  Cracking Due to Stress Corrosion Cracking For cracking due to SCC of stainless steel piping, piping components, and piping elementsexposed to treated water greater than140F, the GALL Report recommends programsconsistent with GALL AMP XI.M7, "BWR Stress Corrosion Cracking" and GALL AMP XI.M2, "Water Chemistry."In LRA Table 3.3.1, Item 3.3.1-38, the applicant stated that the Water Chemistry Control-BWRProgram, manages cracking of stainless steel components. None of the auxiliary system components are within the scope of BWR Stress Corrosion Cracking Program, (all relevant components are included in the reactor vessel, internals and reactor coolant systems). The One-Time Inspection Program, will be used to verify the effectiveness of the Water Chemistry Program.During the audit and review, the staff asked the applicant for clarification on the basis of whichitems were excluded. The applicant stated that all of the components addressed with auxiliary systems were less than 4 inches NPS. The staff reviewed drawings, as documented in the Audit and Review Report, and confirmed that all of the components addressed with the auxiliary systems were less than 4 inches NPS. The staff determines that the applicant's management of cracking of stainless steel flow elements, piping, tubing, and valve bodies of the nuclear boilerand primary containment atmospheric control and containment air dilution system exposed to treated water greater than 140F using the its Water Chemistry Control -BWR Program andOne-Time Inspection Program consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.24  Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting, and crevice corrosion of steel tanks in diesel fuel oilsystem exposed to air - outdoor (external), the GALL Report recommends program consistent with GALL AMP XI.M29, "Aboveground Steel Tanks Program."In LRA Table 3.3.1, Item 3.3.1-40, the applicant stated that the System Walkdown Program,manages loss of material in steel tanks of the diesel fuel oil system exposed to outdoor air through visual inspections.The staff reviewed the applicant's System Walkdown Program and its evaluation is documentedin SER Section 3.0.3.1.9. The System Walkdown Program manages the loss of material due to general, pitting, and crevice corrosion of steel tanks in diesel fuel oil systems exposed to outdoorair through periodic visual inspections which can detect this aging effect/mechanism before the loss of intended function. On this basis, the staff finds this acceptable.
3-280On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
 
3.3.2.1.25  Loss of Material Due to General, Pitting, and Crevice CorrosionFor loss of material due to general, pitting, and crevice corrosion of steel bolting and closurebolting exposed to air, the GALL Report recommends a program consistent with GALL AMP XI.M18, "Bolting Integrity."In LRA Table 3.3.1, Item 3.3.1-43, the applicant stated that the System Walkdown Program,manages the loss of material for steel bolting through the use of visual inspections that are performed at least once per refueling cycle.During the audit and review, the staff asked the applicant to clarify how aging of steel bolting andclosure bolting would be managed in the absence of a Bolting Integrity Program. In a letter dated July 6, 2006, the applicant agreed to prepare and submit an AMP consistent with GALL AMP XI.M18, "Bolting Integrity," for approval. In letters dated October 17, 2006 and January 4, 2007, the applicant revised its LRA, committing (Commitment #34) to a Bolting Integrity Program. The staff's evaluation of the applicant's System Walkdown Program and Bolting Integrity Program are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The program Bolting Integrity Program applies to bolting and torquing practices of safety-related and nonsafety-related carbon and stainless steel bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all safety and nonsafety-relates bolting regardless of size (except the reactor vessel closure studs which are address by the Reactor Vessel Closure Studs Program) and material. The applicant's Bolting Integrity Program conforms to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI. The applicant's System Walkdown Program comprises of inspections of external surfaces of components subject to an AMR. On this basis, the staff finds that the applicant's management of loss of material for steel bolting consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant, with the commitment identifiedabove, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.26  Cracking Due to Stress Corrosion Cracking For cracking due to SCC of stainless steel and stainless clad steel piping, piping components,piping elements, and heat exchanger components exposed to closed cycle cooling water greater than140F, the GALL Report recommends a program consistent with GALL AMP XI.M21,"Closed-Cycle Cooling Water System."In LRA Table 3.3.1, Item 3.3.1-46, the applicant stated that the Water Chemistry Control-ClosedCooling Water Program, manages cracking for stainless steel components.During the audit and review, the applicant stated that for this aging effect, the One-TimeInspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3-2813.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated thatthe LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control - Closed Cooling Water Program.The staff reviewed the applicant's Water Chemistry Control-Closed Cooling Water Program andOne-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.2.18 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-Closed Cooling Water Program is consistent with GALL AMP XI.M21 with one exception which is related to performance testing. This exception would not affect the management of cracking due to SCC.
Therefore, the staff finds that the applicant is managing SCC of stainless steel and stainless clad steel piping, piping components, piping elements, and heat exchanger components exposed toclosed cycle cooling water greater than 140F in a manner consistent with the GALL Report andtherefore acceptable.On the basis of its review, the staff finds that the applicant, with the change in the applicationidentified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.27  Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting, and crevice corrosion of steel piping, pipingcomponents, piping elements, tanks, and heat exchanger components exposed to closed cycle cooling water, the GALL Report recommends a program consistent with GALL AMP XI.M21, "Closed-Cycle Cooling Water System."In the discussion column of LRA Table 3.3.1, Item 3.3.1-47, the applicant stated that, for steelcomponents of most auxiliary systems, the Water Chemistry Control-Closed Cooling Water Program manages loss of material. Furthermore, the applicant stated that the Water Chemistry Control-Auxiliary Systems Program manages loss of material for steel components of the house heating boiler and stator cooling systems.During the audit and review, the applicant stated that for this aging effect, the One-TimeInspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control - Closed Cooling Water Program.The staff reviewed the applicant's Water Chemistry Control-Auxiliary Systems Program. Thisevaluation is documented in SER Section 3.0.3.3.7. The applicant's program is a plant-specific program. This program includes application of the One-Time Inspection Program to verify the effectiveness of the Water Chemistry Control-Auxiliary Systems Program. Therefore, the staff determines that the applicant is adequately managing the loss of material due to general, pitting, and crevice corrosion of steel coolers, filter housings, heat exchangers (shell), piping, pump casings, steam traps, strainer housings, tanks, valve bodies, and copper alloy tubing exposed to treated water in the house heating boiler and stator cooling systems.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
3-2823.3.2.1.28  Loss of Material Due to General, Pitting, Crevice, and Galvanic CorrosionFor loss of material due to general, pitting, crevice, and galvanic corrosion of steel piping, pipingcomponents, piping elements, tanks, and heat exchanger components exposed to closed cycle cooling water, the GALL Report recommends a program consistent with GALL AMP XI.M21, "Closed-Cycle Cooling Water System."In LRA Table 3.3.1, Item 3.3.1-48 the applicant stated that the Water Chemistry Control-ClosedCooling Water Program, manages loss of material for steel heat exchanger components.During the audit and review, the applicant stated that for this aging effect, the One-TimeInspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Closed Cooling Water Program.The staff reviewed the applicant's Water Chemistry Control-Closed Cooling Water Program andOne-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.18 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-Closed Cooling Water Program is consistent with GALL AMP XI.M21 with one exception which is related to performance testing. This exception would not affect the management of loss of material due to general, pitting, crevice, and galvanic corrosion. Therefore, the staff determines that the applicant is managing loss of material due to general, pitting, crevice, and galvanic corrosion of steel heat exchanger components (bonnet, shell, tubes, and tubesheet) exposed to closed cycle cooling water in a manner consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant, with the change in the applicationidentified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.29  Loss of Material Due to Microbiologically-Influenced Corrosion For loss of material due to MIC of stainless steel and steel with stainless steel cladding heatexchanger components exposed to closed cycle cooling water, the GALL Report recommends a program consistent with GALL AMP XI.M21, "Closed-Cycle Cooling Water System."In LRA Table 3.3.1, Item 3.3.1-49, the applicant stated that the Water Chemistry Control-ClosedCooling Water Program manages loss of material for stainless steel heat exchanger components.During the audit and review, the applicant stated that for managing this aging effect, theOne-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Closed Cooling Water Program.
3-283The staff reviewed the applicant's Water Chemistry Control-Closed Cooling Water Program andOne-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.18 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-Closed Cooling Water Program is consistent with GALL AMP XI.M21 with one exception which is related to performance testing. This exception would not affect the management of loss of material due to MIC. Therefore, the staff determines that the applicant is managing loss of material due to MIC of stainless steel and steel with stainless steel cladding heat exchanger components exposed toclosed cycle cooling water in a manner consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant, with the change in the applicationidentified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.30  Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of stainless steel piping, pipingcomponents, and piping elements exposed to closed cycle cooling water, the GALL Report recommends a program consistent with GALL AMP XI.M21, "Closed-Cycle Cooling Water System."In LRA Table 3.3.1, Item 3.3.1-50, the applicant stated that the Water Chemistry Control-ClosedCooling Water Program manages loss of material for stainless steel components and that for stainless steel components of the demineralized water system, the Water Chemistry Control-Auxiliary Systems Program manages loss of material.During the audit and review, the applicant stated that for managing this aging effect, theOne-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Closed Cooling Water Program.The staff reviewed the applicant's Water Chemistry Control-Closed Cooling Water Program andOne-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.18 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-Closed Cooling Water Program is consistent with GALL AMP XI.M21 with one exception which is related to performance testing. This exception would not affect the management of loss of material due to pitting and crevice corrosion. Therefore, the staff determines that the applicant is managing loss of material due to pitting and crevice corrosion of stainless steel piping, piping components, andpiping elements exposed to closed cycle cooling water in a manner consistent with the GALL Report and therefore acceptable.During the audit and review, the staff asked the applicant to clarify why there were no items inLRA Table 3.3.2-13-12 being managed by the Water Chemistry Control-Auxiliary Systems Program as stated in the discussion column of LRA Table 3.3.1, Item 3.3.1-50. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant revised LRA Table 3.3.1, Item 3.3.1-50 to replace the Water Chemistry Control-Auxiliary Systems Program in the Discussion column with the Water Chemistry Control-BWR Program. The LRA Table 3.3.1 item 3-284referenced in LRA Table 3.3.2-13-12 managed by the Water Chemistry Control-BWR Programis LRA Table 3.3.1, Item 3.3.1-17, which the staff evaluated in SER Section 3.3.2.1.7. The staff finds that for LRA Table 3.3.1, Item 3.3.1-17, the applicant stated that the loss of material in steel components is managed by the Water Chemistry Control - BWR Program. The One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program. On this basis, the staff finds this change acceptable.On the basis of its review, the staff finds that the applicant, with the change in the applicationidentified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.31  Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion For loss of material due to pitting, crevice, and galvanic corrosion of copper alloy piping, pipingcomponents, piping elements, and heat exchanger components exposed to closed cycle cooling water, the GALL Report recommends a program consistent with GALL AMP XI.M21, "Closed-Cycle Cooling Water System."In LRA Table 3.3.1, Item 3.3.1-51, the applicant stated that the Water Chemistry Control-ClosedCooling Water Program manages loss of material for copper alloy components.During the audit and review, the applicant stated that for managing this aging effect, theOne-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Closed Cooling Water Program.The staff reviewed the applicant's Water Chemistry Control-Closed Cooling Water Program andOne-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.18 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-Closed Cooling Water Program is consistent with GALL AMP XI.M21 with one exception which is related to performance testing. This exception would not affect the management of loss of material due to pitting, crevice, and galvanic corrosion. Therefore, the staff finds that the applicant is managing loss of material due to pitting, crevice, and galvanic corrosion of copper alloy piping, pipingcomponents, piping elements, and heat exchanger components exposed to closed cycle cooling water in a manner consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant, with the change in the applicationidentified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.In LRA Table 3.3.1, Item 3.3.1-51, the applicant stated that, for copper alloy components of thehouse heating boiler system, demineralized water system, and portions of the HVAC system, the Water Chemistry Control-Auxiliary Systems Program manages loss of material.The applicant's Water Chemistry Control-Auxiliary Systems Program is a plant-specific program.This program includes application of the One-Time Inspection Program to verify the effectiveness of the Water Chemistry Control-Auxiliary Systems Program. The staff evaluations 3-285of these programs are documented in SER Section 3.0.3.3.7 and 3.0.3.1.6, respectively. TheWater Chemistry Control-Auxiliary Systems Program uses specific manufacturer's recommendations and general guidelines provided in EPRI Report 1007820 as acceptance criteria for chemistry parameters. It is combined with the One-Time Inspection Program to confirm the effectiveness of the Water Chemistry-Auxiliary Systems Program. The staff finds this combination of programs will adequately manage this aging effect and their use is acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.3.2.1.32  Reduction of Heat Transfer Due to Fouling For reduction of heat transfer due to fouling of steel, stainless steel, and copper alloy heatexchanger tubes exposed to closed cycle cooling water, the GALL Report recommends programs consistent with GALL AMP XI.M21, "Closed-Cycle Cooling Water System."In LRA Table 3.3.1, Item 3.3.1-52, the applicant stated that the Water Chemistry Control-ClosedCooling Water Program manages reduction of heat transfer for copper alloy heat exchanger tubes exposed to closed cycle cooling water. The applicant also stated that auxiliary systems have no steel or stainless steel heat exchanger tubes exposed to closed cycle cooling water with a heat transfer intended function.During the audit and review, the applicant stated that for managing this aging effect, theOne-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Closed Cooling Water Program.The staff reviewed the applicant's Water Chemistry Control - Closed Cooling Water Programand One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.18 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control -
Closed Cooling Water Program is consistent with GALL AMP XI.M21 with one exception which is related to performance testing.During the audit and review, the staff asked the applicant to clarify how fouling would beadequately managed without performance testing. The applicant addressed the exception to the GALL Report for performance monitoring by stating that the One-Time Inspection Program includes inspections to verify the effectiveness of the water chemistry control AMP s by confirming that unacceptable cracking, loss of material, and fouling is not occurring. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control - Closed Cooling Water Program. The staff's evaluation of this exception is provided in SER Section 3.0.3.2.18.3. The staff determined that the applicant would select representative samples from the low-flow and stagnant flow areas of the listed CCWSs in the One-Time Inspection Program, which will provide assurance that the aging effects for this system will be adequately managed. On this basis, the staff finds this exception acceptable.
3-286On the basis of its review, the staff finds that the applicant, with the change in the applicationidentified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.33  Loss of Material Due to General and Pitting Corrosion For loss of material due to general and pitting corrosion of steel compressed air system piping,piping components, and piping elements exposed to condensation (internal), the GALL Reportrecommends programs consistent with GALL AMP XI.M24, "Compressed Air Monitoring."In LRA Table 3.3.1, Item 3.3.1-53, the applicant stated that the Instrument Air Quality Programmanages loss of material for carbon steel components exposed to treated air.The staff's evaluation of the applicant's Instrument Air Quality Program is documented in SERSection 3.0.3.3.4. The staff determines that the applicant's Instrument Air Quality Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. The program ensures that IA supplied to components is maintained free of water and significant contaminants, thereby preserving an environment that is not conducive to loss of material. On this basis, the staff finds that the applicant's management of the loss of material for carbon steel components exposed to treated air using its Instrument Air Quality Program acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, in a manner consistent with the GALL Report.3.3.2.1.34  Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of stainless steel compressed air systempiping, piping components, and piping elements exposed to internal condensation, the GALLReport recommends programs consistent with GALL AMP XI.M24, "Compressed Air Monitoring."In LRA Table 3.3.1, Item 3.3.1-54, the applicant stated that the Instrument Air Quality Programmanages loss of material for stainless steel components of auxiliary system exposed to treated air.The staff's evaluation of the applicant's Instrument Air Quality Program is documented in SERSection 3.0.3.3.4. The staff determines that the applicant's Instrument Air Quality Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. The program ensures that IA supplied to components is maintained free of water and significant contaminants, thereby preserving an environment that is not conducive to loss of material. On this basis, the staff finds that the applicant's management of the loss of material for stainless steel components of auxiliary system exposed to treated air using its Instrument Air Quality Program acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, in a manner consistent with the GALL Report.
3-2873.3.2.1.35  Increased Hardness, Shrinkage and Loss of Strength Due to WeatheringFor increased hardness, shrinkage and loss of strength due to weathering of elastomer firebarrier penetration seals exposed to air, the GALL Report recommends programs consistent with GALL AMP XI.M26, "Fire Protection."In the LRA Table 3.3.1, Item 3.3.1-61, the applicant stated that this line item was not used in theauxiliary systems tables. Fire barrier seals are evaluated as structural components in LRA Section 3.5. Cracking and the change in material properties of elastomer seals are managed by the Fire Protection Program.During the audit and review, the staff noted that in LRA Table 3.5.2-6 for component elastomerpenetration sealant in a protected from weather environment, the aging effects are cracking and change in material properties. For this line item, two AMPs are shown, Fire Protection and Structures Monitoring. The referenced GALL Report line item is VII.G-1 and the LRATable 3.3.1, Item 3.3.1-61. The GALL Report's Line Item VII.G-1 is for component fire barrierpenetration seals. Furthermore, in the discussion column for LRA Table 3.3.1, Item 3.3.1-61, the applicant stated: Cracking and the change in material properties of elastomer seals are managedby the Fire Protection Program.The applicant was asked to clarify why this AMR line item is not split into two lines: (1)penetration sealant (fire) with AMP Fire Protection, the GALL Report reference VII.G-1, LRATable 1 Line Item 3.3.1-61 and a Note B; and, (2) penetration sealant (flood, radiation) with AMP Structures Monitoring, the GALL Report reference III.A6-12, LRA Table 1 LineItem 3.5.1-44 and a Note C. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to separate this component line item into two line items as follows:Table 3.3-2  AMR Line Items for Elastomer Penetration Sealantsa.Delete line item:Bulk Commodities Structure and/or Component/
Commodity Intended FunctionMaterialEnvironmentAging Effect Requiring ManagementAging Management Program NUREG 1801 Vol.2 Item Table 1 Item N o t e s Penetration sealant (fire, flood, radiation)
EN, FB, FLB, PB, SNSElastomerProtected from weatherCracking,Change in material properties Fire Protection, Structures Monitoring III.A6-1 2 (TP-7)3.5.1-44C 3-288b.Add line item:Bulk Commodities Structure and/or Component/
Commodity Intended FunctionMaterialEnvironmentAging Effect Requiring ManagementAging Management Program NUREG 1801 Vol.2 Item Table 1 Item N o t e s Penetration sealant (fire)EN, FB, PB, SNSElastomerProtected from weatherCracking,Change in material properties Fire ProtectionVII.G-1 (A-19)3.3.1-61Bc.Add line item:Bulk Commodities Structure and/or Component/
Commodity Intended FunctionMaterialEnvironmentAging Effect Requiring ManagementAging Management Program NUREG 1801 Vol.2 Item Table 1 Item N o t e s Penetration sealant (flood, radiation)
EN, FLB, PB, SNSElastomerProtected from weatherCracking,Change in material properties StructuresMonitoring III.A6-1 2 (TP-7)3.5.1-44CDuring the audit and review, the staff noted that in LRA Table 3.5.2-6 for elastomer seismicisolation joints in a protected from weather environment, the aging effects are cracking and change in material properties. The AMP shown is Fire Protection. The referenced GALL Report line item is VII.G-1 and the LRA Table 3.3.1, Item 3.3.1-61. The GALL Report Line Item VII.G-1is for component fire barrier penetration seals. In the discussion column for LRA Table 3.3.1, Item 3.3.1-61, the applicant stated:Cracking and the change in material properties of elastomer seals are managedby the Fire Protection ProgramThere is no mention of seismic gaps. In the discussion column for LRA Table 3.5.1,Item 3.5.1-44, the applicant stated:Loss of sealing is a consequence of elastomer cracking and change in materialproperties. Component types include: moisture barrier, compressible joints and seals used for seismic gaps, and fire barrier seals. The Structures Monitoring Program manages cracking and change in material properties.
3-289Because this discussion addresses seismic gaps and fire barrier seals, the applicant was askedto clarify why this AMR line item does not show Structures Monitoring as the AMP instead of Fire Protection with the GALL Report reference III.A6-12, LRA Table 3.5.1, Item 3.5.1-44 with aNote C. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to denote the following changes:1.Note C is changed to Note E for this line item.
2.The discussion in LRA Table 3.3.1, Item 3.3.1-61 is revised to readas follows. "This line item was not used in the auxiliary systems tables. Fire barrier seals are evaluated as structural components in Section 3.5. Cracking and change in material properties of elastomer seals, including seismic isolation joints located in fire barriers, are managed by the Fire Protection Program."3.An additional line item is added to read as follows.Table 3.3-3  AMR Line Item for Elastomer Seismic Isolation JointsBulk Commodities Structure and/or Component/
Commodity Intended FunctionMaterialEnvironmentAging Effect Requiring ManagementAging Management Program NUREG 1801 Vol.2 Item Table 1 Item N o t e sSeismic isolation jointSSRElastomerProtected from weatherCracking,Change in material properties StructuresMonitoring III.A6-1 2 (TP-7)3.5.1-44COn the basis of its review, the staff finds that the applicant, with the change in the applicationidentified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.36  Loss of Material Due to Wear For loss of material due to wear of steel fire rated doors exposed to air, the GALL Reportrecommends a program consistent with GALL AMP XI.M26, "Fire Protection."In LRA Table 3.3.1, Item 3.3.1-63, the applicant stated that this line item was not used in theauxiliary systems tables. Steel fire doors are evaluated as structural components in LRA Section 3.5. The loss of material for fire doors is managed by the Fire Protection Program.During the audit and review, the staff noted that in LRA Table 3.5.2-6 for carbon steel fire doorsin a protected from weather environment, the aging effect is loss of material. The referenced GALL Report line item is VII.G-3 and the LRA Table 3.3.1 Item is 3.3.1-63. The GALL ReportLine Item VII.G-3 is for component fire rated doors. The applicant was asked to clarify why thenote is C, (different component but consistent with the GALL Report otherwise) for this AMR line 3-290item, instead of Note B (consistent with the GALL Report, but AMP takes exceptions). In a letterdated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA is revised to change 'Note C' to 'Note B' for this line item. The staff finds this change acceptable.On the basis of its review, the staff finds that the applicant, with the change in the applicationidentified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.37  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-InfluencedCorrosion, and FoulingFor loss of material due to general, pitting, crevice, and MIC, and fouling of steel piping, pipingcomponents, and piping elements exposed to raw water, the GALL Report recommends a program consistent with GALL AMP XI.M27, "Fire Water System."In LRA Table 3.3.1, Item 3.3.1-68, the applicant stated that the loss of material in steelcomponents exposed to raw or untreated water is managed by the Fire Water System Program.The staff reviewed the applicant's Fire Water System Program and its evaluation is documentedin SER Section 3.0.3.2.12. The staff determined that the applicant's Fire Water System Program consistent with GALL AMP XI.M27, with exceptions and enhancement, and finds that the applicant's Fire Water System Program provided assurance that the aging effects for the components in the scope of its Fire Water System Program are adequately managed. The applicant also stated, in the LRA, that for carbon steel filter housing, strainer housing, tanks,traps, and valve bodies of the IA and PW systems exposed to untreated water, the Periodic Surveillance and Preventive Maintenance Program manages loss of material.The staff's review of the applicant's Periodic Surveillance and Preventive Maintenance Programis documented in SER Section 3.0.3.3.5. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for loss of material from carbon steel filter housing, strainer housing, tanks, traps, and valve bodies of the IA and PW systems, which the staff found acceptable.The applicant stated, in the LRA, that for carbon steel piping retired in place, piping of thepotable water system, as well as orifices, piping, pump casings, strainer housings, and valve bodies of the radwaste systems, the applicant proposes to manage loss of material due to general, pitting, crevice, and MIC in untreated water using the One-Time Inspection Program.In RAI 3.3.1-68-K-01, the staff requested that the applicant provide justification for the use of theOne-Time Inspection Program to management aging of carbon steel exposed to raw water in the potable water system; radwaste, liquid and solid system; and equipment retired in place system as opposed to a periodic inspection. In its response, by letter dated September 5, 2006, the applicant states that the "untreatedwater" environment for the carbon steel potable water system components in LRA Table 3.3.2-13-29 is not "raw water"; it is actually treated water. Water for this system comes from onsite wells and is monitored and treated to meet the regulations of the state of Vermont. It was labeled "untreated water" because conductivity and dissolved oxygen are not monitored.
3-291Carbon steel is not expected to experience significant aging effects in this treated waterenvironment. The applicant states that a One-Time Inspection of carbon steel potable water system components exposed to "untreated water" will be performed to confirm the absence of significant aging effects. If the One-Time Inspection identifies significant aging effects, the corrective action program will ensure that appropriate followup actions are implemented including periodic inspections, if necessary.The applicant also stated that the "untreated water" environment for the carbon steel and copperalloy radwaste system components in LRA Table 3.3.2-13-32 is originally treated water that may now contain contaminants. Therefore, the aging management program has been changed, from One-Time Inspection Program to Periodic Surveillance and Preventive Maintenance Program for managing loss of material for carbon steel and copper alloy components in the radwaste system exposed to untreated water (LRA Table 3.3.2-13-32). The "untreated water" environment for the equipment retired in place system carbon steel piping component in LRA Table 3.3.2-13-35 should be listed as Air - indoor (int) and that the LRA table will be changed to reflect the above environment.Based on its review, the staff finds the applicant's response to RAI 3.3.1-68-K-03 acceptablebecause this is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for loss of material from carbon steel components exposed to raw water in the potable water; radwaste, liquid and solid; and equipment retired in place systems. The staff's concern described in RAI 3.3.1-68-K-03 is resolved.On the basis of its review, the staff finds that the applicant, with the satisfactory resolution of therequest for additional information identified above, appropriately addressed the aging effect/mechanism, in a manner consistent with the GALL Report.3.3.2.1.38  Loss of Material Due to Pitting and Crevice Corrosion, and Fouling For loss of material due to pitting and crevice corrosion, and fouling of stainless steel piping,piping components, and piping elements exposed to raw water, the GALL Report recommends a program consistent with GALL AMP XI.M27, "Fire Water System."In LRA Table 3.3.1, Item 3.3.1-69, the applicant stated that the loss of material in stainless steelcomponents exposed to raw water is managed by the Fire Water System Program, Fire Protection Program, and the One-Time Inspection Program.During the audit and review, the staff noted that the applicant did not apply the One-TimeInspection Program to any AMR line items to which LRA Table 3.3.1, Item 3.3.1-69 was applied (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA.
The applicant revised the LRA to remove the reference to the One-Time Inspection Program in LRA Table 3.3.1, Item 3.3.1-69. The staff finds this acceptable.The staff also asked the applicant to justify the application of the Fire Protection Program ratherthan the Fire Water System Program to manage filters and filter housings in raw water. The applicant explained that the components in question were managed as support components of the engine that drives the fire pump. The Fire Protection Program performs tests and inspections of the diesel engine and its support components and is therefore credited for these components.
3-292The staff reviewed the applicant's Fire Protection Program and its evaluation is documented inSER Section 3.0.3.2.11. This AMP is consistent, with exceptions and enhancements, with GALL AMP XI.M26, "Fire Protection." The staff determined it to be an acceptable method for management of loss of material from EDG stainless steel filters and filter housings exposed to raw water. The staff determined that management of the stainless steel filters and filter housings in the fire protection water system using the Fire Protection Program to be consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant, with the change in the applicationidentified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.3.2.1.39  Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion, and FoulingFor loss of material due to pitting, crevice, and MIC, and fouling of copper alloy piping, pipingcomponents, and piping elements exposed to raw water, the GALL Report recommends programs consistent with GALL AMP XI.M27, "Fire Water System."In LRA Table 3.3.1, Item 3.3.1-70, the applicant stated that the loss of material in copper alloycomponents exposed to raw water is managed by the Fire Water System Program, Fire Protection Program, and the One-Time Inspection Program.The staff asked the applicant to justify the application of the Fire Protection Program rather thanthe Fire Water System Program to manage copper-alloy heat exchangers and tubing in raw water. The applicant explained that the components in question were managed as support components of the engine that drives the fire pump. The Fire Protection Program performs tests and inspections of the diesel engine and its support components and is therefore credited for these components.The staff reviewed the applicant's Fire Protection Program and its evaluation is documented inSER Section 3.0.3.2.11. This AMP is consistent, with exceptions and enhancements, with GALL AMP XI.M26, "Fire Protection." The staff determines it to be an acceptable method for management of loss of material from fire water system copper-alloy heat exchangers and tubing exposed to raw water.The staff determines that management of the copper-alloy heat exchangers and tubing in thefire protection water system using the Fire Protection Program to be consistent with the GALL Report and therefore acceptable.During the audit and review, the staff asked the applicant to justify the application of theOne-Time Inspection Program rather than the Fire Water System Program to manage copper-alloy tubing in untreated water of the radwaste, liquid and solid system. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant revised LRA Table 3.3.2-13-32 to replace the AMP of One-Time Inspection with the Periodic Surveillance and Preventive Maintenance Program for all line items containing carbon steel and copper alloy with an environment of untreated water.
3-293The staff's evaluation of the applicant's Periodic Surveillance and Preventive MaintenanceProgram is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. The Periodic Surveillance and Preventive Maintenance Program manages loss of material of copper-alloy tubing exposed to untreated water by visual inspections or other NDE techniques. On this basis, the staff determines that this program is capable of detecting loss of material for copper-alloy tubing. On the basis of its review, the staff finds that the applicant, with the application changesidentified above, appropriately addressed the aging effect/mechanism, in a manner consistent with the GALL Report.3.3.2.1.40  Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting, and crevice corrosion of steel piping, pipingcomponents, and piping elements exposed to moist air or condensation (internal), the GALL Report recommends programs consistent with GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components."In LRA Table 3.3.1, Item 3.3.1-71, the applicant stated that the loss of material for steelcomponents exposed to moist air or condensation is managed by the Periodic Surveillance and Preventive Maintenance Program using visual inspections or other NDE techniques. The staff's review of the applicant's Periodic Surveillance and Preventive Maintenance Programis documented in SER Section 3.0.3.3.5. The Periodic Surveillance and Preventive Maintenance Program will manage the loss of material through visual inspections or other NDE techniques.
On this basis, the staff determines that the aging of the steel piping, piping components, and piping elements is adequately managed.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, in a manner consistent with the GALL Report.3.3.2.1.41  Loss of Material Due to General, Pitting, Crevice, and (For Drip Pans and DrainLines) Microbiologically-Influenced CorrosionIn LRA Table 3.3.1, Item 3.3.1-72, the applicant stated that loss of material of steel componentinternal surfaces exposed to condensation is managed by the Periodic Surveillance and Preventive Maintenance Program, using visual inspections or other NDE techniques.The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program.This evaluation is documented in SER Section 3.0.3.3.5. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for loss of material from carbon steel exposed to condensation in fan housings of the SWS and from carbon steel exposed to condensation in heat exchanger housings of the HVAC system.
3-294On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, in a manner consistent with the GALL Report.3.3.2.1.42  Loss of Material Due to General Corrosion In LRA Table 3.3.1, Item 3.3.1-73, the applicant stated that this line item was not used in theauxiliary systems tables. Steel crane structural girders are evaluated as structural components in SER Section 3.5. Loss of material for steel crane structural components is managed by the Periodic Surveillance and Preventive Maintenance Program and the Structures Monitoring Program.During the audit and review, the applicant confirmed that aging management of steel cranestructural girders in load handling will conform to the standards cited in GALL AMP XI.M23 "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems."
The applicant's technical personnel stated that reactor building steel crane structural girders used in load handling are inspected in accordance with the Periodic Surveillance and Preventive Maintenance Program and process facility crane rails and girders are inspected in accordance with the Structures Monitoring Program. The Structures Monitoring Program will be enhanced, as identified in Appendix B, to address crane rails and girders. Aging management activities for crane rails and girders in accordance with these two programs are consistent with the program element described for in GALL AMP XI.M23.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, in a manner consistent with the GALL Report.3.3.2.1.43  Loss of Material Due to General, Pitting, Crevice, Galvanic, andMicrobiologically-Influenced Corrosion, and FoulingFor loss of material due to general, pitting, crevice, galvanic, and MIC, and fouling of steel heatexchanger components exposed to raw water, the GALL Report recommends programs consistent with GALL AMP XI.M20, "Open-Cycle Cooling Water System."In LRA Table 3.3.1, Item 3.3.1-77, the applicant stated that management of this aging effect isconsistent with the GALL Report for most auxiliary systems. The Service Water Integrity Program manages loss of material for steel heat exchanger. For steel heat exchanger tubes of the reactor building CCWS, the Heat Exchanger Monitoring Program manages loss of material. The staff's evaluation of the applicant's Service Water Integrity Program is documented in SERSection 3.0.3.2.16. The applicant's aging management of loss of material due to general, pitting, crevice, galvanic, and MIC, and fouling of steel heat exchanger components is consistent with the GALL Report and therefore acceptable.The staff's evaluation of the applicant's Heat Exchanger Monitoring Program is documented inSER Section 3.0.3.3.1. The Heat Exchanger Monitoring Program manages the loss of material for steel heat exchanger tubes of the reactor building through visual inspections or eddy current inspections on selected heat exchangers in various systems. On this basis, the staff determines that the aging of steel heat exchanger of the reactor building is adequately managed.
3-295On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, in a manner consistent with the GALL Report.3.3.2.1.44  Reduction of Heat Transfer Due to Fouling For reduction of heat transfer due to fouling of stainless steel and copper alloy heat exchangertubes exposed to raw water, the GALL Report recommends programs consistent with GALL AMP XI.M20, "Open-Cycle Cooling Water System."In LRA Table 3.3.1, Item 3.3.1-83, the applicant stated that for the fire protection system, theFire Protection Program manages reduction of heat transfer in copper alloy heat exchanger tubes.During the audit and review, the staff asked the applicant to clarify the basis for management offouling of copper alloy heat exchanger tubes exposed to raw water using the Fire Protection Program. The applicant stated that the heat exchangers represented are the fire pump diesel jacket water heat exchanger and the gear box oil cooler. Both heat exchangers use water from the fire water system (raw water) for cooling. The Fire Protection Program performs tests and inspections of the diesel engine. Since these heat exchangers are part of the fire diesel it is appropriate to manage fouling with the Fire Protection Program which tests the engine and its auxiliaries. The staff reviewed the applicant's Fire Protection Program and its evaluation is documented inSER Section 3.0.3.2.11. This AMP is consistent, with exceptions and enhancements, with GALL AMP XI.M26, "Fire Protection." The staff determines it to be an acceptable method for management of fouling of copper-alloy heat exchanger tubes exposed to raw water.The staff determines that management of fouling of the copper-alloy heat exchanger tubes in thefire protection water system using the fire protection AMP to be consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff determines that the applicant appropriately addressed theaging effect/mechanism, in a manner consistent with the GALL Report.
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determines that the applicant adequately addressed the issues that were further evaluated. The staff finds that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-296The staff evaluated the applicant's claim of consistency with the GALL Report. The staff alsoreviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed consistent with its AMRs. Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is RecommendedSummary of Technical Information in the Amended Application. In LRA Section 3.3.2.2, theapplicant further evaluates aging management, as recommended by the GALL Report, for the auxiliary systems components and provides information concerning how it will manage the following aging effects:
* cumulative fatigue damage
* reduction of heat transfer due to fouling
* cracking due to stress corrosion cracking
* cracking due to stress corrosion cracking and cyclic loading
* hardening and loss of strength due to elastomer degradation
* reduction of neutron-absorbing capacity and loss of material due to general corrosion
* loss of material due to general, pitting, and crevice corrosion
* loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion
* loss of material due to general, pitting, crevice, microbiologically-influenced corrosion andfouling
* loss of material due to pitting and crevice corrosion
* loss of material due to pitting, crevice, and galvanic corrosion
* loss of material due to pitting, crevice, and microbiologically-influenced corrosion
* loss of material due to wear
* loss of material due to cladding breach
* quality assurance for aging management of nonsafety-related componentsStaff Evaluation. For component groups evaluated in the GALL Report, for which the applicantclaimed consistency with the report and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations against the criteria contained in SRP-LR Section 3.3.2.2. The staff's review of the applicant's further evaluation follows.
3-2973.3.2.2.1  Cumulative Fatigue DamageLRA Section 3.3.2.2.1 states that fatigue is a TLAA, as required by 10 CFR 54.3. Applicantsmust evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.3.3.2.2.2  Reduction of Heat Transfer Due to Fouling The staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR Section 3.3.2.2.2.
LRA Section 3.3.2.2.2 addresses the reduction of heat transfer of stainless steel heat exchangertubes exposed to treated water due to fouling.SRP-LR Section 3.3.2.2.2 states that reduction of heat transfer due to fouling may occur instainless steel heat exchanger tubes exposed to treated water. The existing program controls water chemistry to manage reduction of heat transfer due to fouling. However, control of water chemistry may be inadequate; therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that reduction of heat transfer due to fouling does not occur. A one-time inspection is an acceptable method to ensure that reduction of heat transfer does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated that reduction of heat transfer due to fouling for stainless steel heatexchanger tubes exposed to treated water is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicant's Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including areas of stagnant flow.The staff finds this to be consistent with the criteria of SRP-LR Section 3.3.2.2.2 and thereforeacceptable.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.3.2.2.2 criteria. For those line items that apply to LRA Section 3.3.2.2.2, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-2983.3.2.2.3  Cracking Due to Stress Corrosion CrackingThe staff reviewed LRA Section 3.3.2.2.3 against the following SRP-LR Section 3.3.2.2.3criteria:  (1)LRA Section 3.3.2.2.3 addresses the cracking due to SCC, this aging effect is notapplicable to VYNPS. Cracking due to SCC can occur in the stainless steel piping, pipingcomponents, and piping elements of the BWR SLC system that are exposed to sodium pentaborate solution greater than 140F. At VYNPS, the sodium pentaborate solution inthe SLC system does not exceed 140F. Therefore cracking due to SCC is not an AERMfor the SLC system. This item is not applicable to VYNPS.SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in the stainlesssteel piping, piping components, and piping elements of the BWR SLC system that areexposed to sodium pentaborate solution greater than 60 C (140 F). The existingAMP monitors and controls water chemistry to manage the aging effects of cracking due to SCC. However, high concentrations of impurities in crevices and with stagnant flow conditions may cause SCC; therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that SCC does not occur. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that SCC does not occur and that component intended functions will be maintained during the period of extended operation.The staff determines that although the SLC injects through the drywell, where ambienttemperatures may exceed 140F, sodium pentaborate is not normally present in thisportion of the system. For this reason, the staff finds that cracking in the SLC system due to SCC does not require aging management at VYNPS.On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS.  (2)LRA Section 3.3.2.2.3 addresses cracking of stainless steel heat exchanger componentsexposed to treated water greater than 140F due to SCC.SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in stainless steeland stainless clad steel heat exchanger components exposed to treated water greater than 60 C (140 F). The GALL Report recommends further evaluation of a plant-specificAMP to ensure that these aging effects are adequately managed.
3-299The applicant stated, in the LRA, that cracking due to SCC in stainless steel heatexchanger components exposed to treated water greater than 140F is an AERM atVYNPS. There are no auxiliary system components at VYNPS with stainless steel cladding. For VYNPS auxiliary systems these stainless steel heat exchanger components are managed by the Water Chemistry Control-BWR Program. This program monitors parameters and contaminants to ensure they remain within the limits specified by the EPRI guidelines. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program for managing cracking using visual and ultrasonic inspection techniques.The use of the applicant's One-Time Inspection Program in conjunction with its WaterChemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program.The staff finds that this combination satisfies the criteria of SRP-LR Appendix A.1 andtherefore is acceptable.
 
  (3)LRA Section 3.3.2.2.3 addresses cracking of stainless steel diesel engine exhaust pipingexposed to diesel exhaust due to SCC.SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in stainless steeldiesel engine exhaust piping, piping components, and piping elements exposed to dieselexhaust. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed.The applicant stated, in the LRA, that cracking due to SCC in stainless steel dieselengine exhaust piping exposed to diesel exhaust is an AERM at VYNPS. At VYNPS, cracking of stainless steel exhaust piping in the EDG system is managed by the PeriodicSurveillance and Preventive Maintenance Program. This program uses visual and other NDE techniques to manage cracking of the piping. These inspections will manage the aging effect of cracking such that the intended function of the component will not be affected.The applicant's Periodic Surveillance and Preventive Maintenance Program is aplant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for cracking of stainless steel due to SCC when exposed to diesel exhaust.The staff finds that this satisfies the criteria of SRP-LR Section 3.3.2.2.3 and is thereforeacceptable.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.3.2.2.3 criteria. For those line items that apply to LRA Section 3.3.2.2.3, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-3003.3.2.2.4  Cracking Due to Stress Corrosion Cracking and Cyclic LoadingThe staff reviewed LRA Section 3.3.2.2.4 against the following SRP-LR Section 3.3.2.2.4criteria:  (1)LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading.SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occurin stainless steel PWR non-regenerative heat exchanger components exposed to treated borated water greater than 60 C (140 F) in the chemical and volume control system.The existing AMP monitors and controls primary water chemistry in PWRs to manage the aging effects of cracking due to SCC. However, control of water chemistry does not preclude cracking due to SCC and cyclic loading; therefore, the effectiveness of water chemistry control programs should be verified to ensure that cracking does not occur.
The GALL Report recommends that a plant-specific AMP be evaluated to verify the absence of cracking due to SCC and cyclic loading to ensure that these aging effects are adequately managed. An acceptable verification program is to include temperature and radioactivity monitoring of the shell side water and eddy current testing of tubes. VYNPS is a BWR and does not have a non-regenerative heat exchanger exposed to treated borated water. This item is not applicable to VYNPS. The staff confirmed that VYNPS has no components from this group.
On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS.  (2)LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loadingSRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occurin stainless steel PWR regenerative heat exchanger components exposed to treated borated water greater than 60C (140 F). The existing AMP monitors and controlsprimary water chemistry in PWRs to manage the aging effects of cracking due to SCC.
However, control of water chemistry does not preclude cracking due to SCC and cyclic loading; therefore, the effectiveness of water chemistry control programs should be verified to ensure that cracking does not occur. The GALL Report recommends that a plant-specific AMP be evaluated to verify the absence of cracking due to SCC and cyclic loading to ensure that these aging effects are adequately managed. VYNPS is a BWR and does not have a regenerative heat exchanger exposed to treated borated water. This item is not applicable to VYNPS.The staff confirmed that VYNPS has no components from this group.
On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS.
3-301  (3)LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading.SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occurin the stainless steel pump casing for the PWR high-pressure pumps in the chemical and volume control system. The existing AMP monitors and controls primary water chemistry in PWRs to manage the aging effects of cracking due to SCC. However, control of water chemistry does not preclude cracking due to SCC and cyclic loading; therefore, the effectiveness of water chemistry control programs should be verified to ensure that cracking does not occur. The GALL Report recommends that a plant-specific AMP be evaluated to verify the absence of cracking due to SCC and cyclic loading to ensure that these aging effects are adequately managed. VYNPS is a BWR and does not have a chemical and volume control system. This item is not applicable to VYNPS.The staff confirmed that VYNPS has no components from this group.
On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS.3.3.2.2.5  Hardening and Loss of Strength Due to Elastomer Degradation The staff reviewed LRA Section 3.3.2.2.5 against the following SRP-LR Section 3.3.2.2.5criteria:  (1)LRA Section 3.3.2.2.5 addresses cracking and change of material properties due toelastomer degradation in elastomer duct flexible connections of the HVAC systems exposed to air-indoor.SRP-LR Section 3.3.2.2.5 states that hardening and loss of strength due to elastomerdegradation may occur in elastomer seals and components of heating and ventilation systems exposed to air-indoor uncontrolled (internal/external). The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed.The applicant stated in the LRA that cracking and change in material properties due toelastomer degradation in elastomer duct flexible connections of the HVAC systems exposed to air-indoor are an AERM at VYNPS. These aging effects are managed by the Periodic Surveillance and Preventive Maintenance Program. This program includes visual inspections and physical manipulation of the flexible connections to confirm that the components are not experiencing any aging that would affect accomplishing their intended functions.The applicant's Periodic Surveillance and Preventive Maintenance Program is aplant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for cracking and change of material properties due to elastomer degradation in elastomer duct flexible connections of the HVAC systems exposed to air.
3-302The staff finds that this satisfies the criteria of SRP-LR Section 3.3.2.2.5 and is thereforeacceptable.  (2)LRA Section 3.3.2.2.5 addresses the hardening and loss of strength due to elastomerdegradation, this aging effect is not applicable to VYNPS. For the auxiliary systems at VYNPS, no credit is taken for any elastomer linings to prevent loss of material from the underlying carbon steel material such that the material is identified as carbon steel for the AMR. This item is not applicable to VYNPS.SRP-LR Section 3.3.2.2.5 states that hardening and loss of strength due to elastomerdegradation may occur in elastomer linings of the filters, valves, and ion exchangers in spent fuel pool cooling and cleanup systems (BWR and PWR) exposed to treated water or treated borated water. The GALL Report recommends that a plant-specific AMP be evaluated to determine and assess the qualified life of the linings in the environment to ensure that these aging effects are adequately managed.In the discussion column of LRA Table 3.3.1, Item 3.3.1-12, the applicant stated thatthere are no elastomer lined components exposed to treated water in the auxiliary systems.The staff confirmed that VYNPS has no components from this group. On the basis thatVYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.3.2.2.5 criteria. For those line items that apply to LRA Section 3.3.2.2.5, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.2.6  Reduction of Neutron-Absorbing Capacity and Loss of Material Due to GeneralCorrosionThe staff reviewed LRA Section 3.3.2.2.6 against the criteria in SRP-LR Section 3.3.2.2.6.
LRA Section 3.3.2.2.6 addresses the loss of material and cracking of Boral spent fuel storageracks exposed to a treated water environment due to general corrosion.SRP-LR Section 3.3.2.2.6 states that reduction of neutron-absorbing capacity and loss ofmaterial due to general corrosion may occur in the neutron-absorbing sheets of BWR and PWR spent fuel storage racks exposed to treated water or treated borated water. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed.The applicant stated, in the LRA, that loss of material and cracking are an AERM for Boral spentfuel storage racks exposed to a treated water environment. These aging effects are managed by the Water Chemistry Control-BWR Program.
3-303In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRAis revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-BWR Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program. The Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry to manage aging effects caused by corrosion. The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds the aging effect of loss of material due to general corrosion to be adequately managed.The applicant also stated that reduction of neutron-absorbing capacity is insignificant andrequires no aging management. The potential for aging effects due to sustained irradiation of Boral was previously evaluated by the staff and determined to be insignificant. Plant operating experience with Boral coupons inspected in 1991 and 1996 is consistent with the staff's conclusion. Therefore, the staff finds that reduction of neutron-absorbing capacity does not require aging management. Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.3.2.2.6 criteria. For those line items that apply to LRA Section 3.3.2.2.6, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.2.7  Loss of Material Due to General, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.3.2.2.7 against the following SRP-LR Section 3.3.2.2.7criteria:  (1)LRA Section 3.3.2.2.7 addresses the loss of material of carbon steel piping andcomponents in other auxiliary systems exposed to treated water due to general, pitting and crevice corrosion.SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevicecorrosion may occur in steel piping, piping components, and piping elements, includingthe tubing, valves, and tanks in the reactor coolant pump oil collection system, exposed to lubricating oil (as part of the fire protection system). The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of the lubricating oil program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. In addition, corrosion may occur at locations in the reactor coolant pump oil collection tank where water from wash-downs may accumulate; therefore, the effectiveness of the program should be verified to ensure that 3-304corrosion does not occur. The GALL Report recommends further evaluation of programsto manage loss of material due to general, pitting, and crevice corrosion, including determination of the thickness of the lower portion of the tank. A one-time inspection is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated, in the LRA, that steel piping and components in auxiliary systems atVYNPS that are exposed to lubricating oil are managed by the Oil Analysis Program, which includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. Operating experience at VYNPS has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion has not and will not affect the intended functions of these components. During the audit and review, the staff determines that Oil Analysis Program alone is notsufficient in managing the loss of material of steel piping, piping components, and pipingelements, including the tubing, and valves, exposed to lubricating oil (as part of the fire protection system). In a letter dated July 14, 2006, the applicant revised its LRA to state that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program. The staff finds that, based on the programs identified above, the applicant has met thecriteria of SRP-LR Section 3.3.2.2.7. Also, in the LRA, the applicant stated that VYNPS is a BWR with an inert containmentatmosphere and has no reactor coolant pump oil collection system.The staff confirmed that VYNPS has no components from this group.
On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS.  (2)LRA Section 3.3.2.2.7 addresses loss of material of carbon steel piping and componentsin other auxiliary systems exposed to treated water due to general, pitting and crevice
 
corrosion.SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevicecorrosion may occur in steel piping, piping components, and piping elements in the BWRRWCU and shutdown cooling systems exposed to treated water. The existing AMP monitors and controls reactor water chemistry to manage the aging effects of loss of material from general, pitting, and crevice corrosion. However, high concentrations of impurities in crevices and with stagnant flow conditions may cause general, pitting, or crevice corrosion; therefore, the effectiveness of the chemistry control program should be 3-305verified to ensure that corrosion does not occur. The GALL Report recommends furtherevaluation of programs to manage loss of material from general, pitting, and crevice corrosion to verify the effectiveness of the water chemistry program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated in the LRA that VYNPS does not have a separate shutdown coolingsystem. Loss of material due to general, pitting, and crevice corrosion in carbon steel piping and components in other auxiliary systems exposed to treated water are managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including areas of stagnant flow.The staff reviewed the applicant's Water Chemistry Control-BWR Program andOne-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements. This combination satisfies the criteria of SRP-LR Section 3.2.2.2.7 and therefore is acceptable.The staff finds this to be consistent with the criteria of SRP-LR Section 3.3.2.2.7 andtherefore acceptable.  (3)LRA Section 3.3.2.2.7 addresses the loss of material of carbon steel and stainless steeldiesel exhaust piping and components exposed to diesel exhaust in the EDG and JohnDeere Diesel generator systems due to general (steel only), pitting and crevice corrosion.
SRP-LR Section 3.3.2.2.7 states that loss of material due to general (steel only), pitting,and crevice corrosion may occur in steel and stainless steel diesel exhaust piping, pipingcomponents, and piping elements exposed to diesel exhaust. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed.The applicant stated in the LRA that loss of material due to general (steel only), pittingand crevice corrosion for carbon steel and stainless steel diesel exhaust piping andcomponents exposed to diesel exhaust in the EDG and John Deere Diesel generator systems is managed by the Periodic Surveillance and Preventive Maintenance Program.
This program uses visual and other NDE techniques to manage loss of material for these components. The carbon steel and stainless steel diesel exhaust piping and components 3-306in the fire protection system are managed by the Fire Protection Program. Theapplicant's Fire Protection Program uses visual inspections of diesel exhaust piping andcomponents to manage loss of material. These inspections in the Periodic Surveillance and Preventive Maintenance Program and Fire Protection Program will manage the aging effect of loss of material such that the intended function of the components will not be affected.The staff reviewed the applicant's Periodic Surveillance and Preventive MaintenanceProgram. The Periodic Surveillance and Preventive Maintenance manages the loss of material due to general, pitting, and crevice corrosion through periodic inspections and tests. These inspections and tests include visual or other NDE techniques. On this basis, the staff determines that the aging of the steel and stainless steel diesel exhaust piping,piping components, and piping elements exposed to diesel exhaust is adequatelymanaged.The staff also reviewed the applicant's Fire Protection Program and its evaluation isdocumented in SER Section 3.0.3.2.11. The Fire Protection Program uses visual inspections of diesel exhaust piping and components. This AMP is consistent, withexceptions and enhancements, with GALL AMP XI.M26, "Fire Protection." On this basis, staff determines that the aging of the carbon steel and stainless steel diesel exhaust piping and components in the fire protection system is adequately managed. The staff finds that, based on the programs identified above, the applicant has met thecriteria of SRP-LR Section 3.3.2.2.7. Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.3.2.2.7 criteria. For those line items that apply to LRA Section 3.3.2.2.7, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.2.8  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-InfluencedCorrosionThe staff reviewed LRA Section 3.3.2.2.8 against the criteria in SRP-LR Section 3.3.2.2.8.
LRA Section 3.3.2.2.8 addresses loss of material of carbon steel (with or without coating orwrapping) piping and components buried in soil in the SW, fuel oil, and fire protection-water systems due to general, pitting, crevice, and MIC.
 
SRP-LR Section 3.3.2.2.8 states that loss of material due to general, pitting, and crevice corrosion, and MIC may occur in steel (with or without coating or wrapping) piping, piping components, and piping elements buried in soil. Buried piping and tanks inspection programs rely on industry practice, frequency of pipe excavation, and operating experience to manage the 3-307effects of loss of material from general, pitting, and crevice corrosion, and MIC. Theeffectiveness of the buried piping and tanks inspection program should be verified to evaluate an applicant's inspection frequency and operating experience with buried components, ensuring that loss of material does not occur.The applicant stated in the LRA that loss of material due to general, pitting, crevice, and MIC forcarbon steel (with or without coating or wrapping) piping and components buried in soil in the SW, fuel oil, and fire protection-water systems is managed by the Buried Piping Inspection Program. This program will include: (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel components.The applicant also stated that buried components are to be inspected when excavated duringmaintenance. An inspection will be performed within 10 years of entering the period of extended operation, unless an opportunistic inspection occurs within this ten-year period. This program will manage the aging effect of loss of material such that the intended function of the components will not be affected.During the audit and review, the staff confirmed that buried piping has already been inspectedwithin the final ten-year period before the period of extended operation. Therefore, even if no other buried piping is examined before the period of extended operation, VYNPS has complied with staff guidance regarding the examination of buried piping before the end of the current operating license. The proposed schedule for inspection (if there is no other opportunity) is consistent with the staff's position and therefore acceptable.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.3.2.2.8 criteria. For those line items that apply to LRA Section 3.3.2.2.8, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.2.9  Loss of Material Due to General, Pitting, Crevice, Microbiologically-InfluencedCorrosion and FoulingThe staff reviewed LRA Section 3.3.2.2.9 against the following SRP-LR Section 3.3.2.2.9criteria:  (1)LRA Section 3.3.2.2.9 addresses the loss of material of carbon steel piping andcomponents exposed to fuel oil due to general, pitting, crevice, and MIC.SRP-LR Section 3.3.2.2.9 states that loss of material due to general, pitting, and crevicecorrosion, MIC, and fouling may occur in steel piping, piping components, pipingelements, and tanks exposed to fuel oil. The existing AMP relies on fuel oil chemistry programs to monitor and control fuel oil contamination to manage loss of material due to corrosion or fouling. Corrosion or fouling may occur at locations where contaminants accumulate. The effectiveness of fuel oil chemistry programs should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of 3-308programs to manage loss of material due to general, pitting, and crevice corrosion, MIC,and fouling to verify the effectiveness of fuel oil chemistry programs. A one-time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated in the LRA that fouling is not an AERM for the fuel oil system atVYNPS. Loss of material due to general, pitting, crevice, and MIC for carbon steel piping and components exposed to fuel oil is an AERM at VYNPS and these components are managed by the Diesel Fuel Monitoring Program. This program includes sampling and monitoring of fuel oil quality to ensure they remain within the limits specified by the ASTM standards. Maintaining parameters within limits ensures that significant loss of material will not occur. Ultrasonic inspection of storage tank bottoms where water and contaminants accumulate will be performed to confirm the effectiveness of the Diesel Fuel Monitoring Program. In addition, operating experience has confirmed the effectiveness of this program in maintaining fuel oil quality within limits such that loss of material will not affect the intended functions of these components.During the audit and review, the staff determines that Diesel Fuel Monitoring Programalone is not sufficient in managing the loss of material of steel piping, piping components,piping elements, and tanks exposed to fuel oil. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program verifies the effectiveness of the Diesel Fuel Monitoring Program.The staff finds that, based on the programs and LRA review identified above, theapplicant has met the criteria of SRP-LR Section 3.3.2.2.9.    (2)LRA Section 3.3.2.2.9 addresses loss of material of carbon steel heat exchangercomponents exposed to lubricating oil due to general, pitting, crevice, MIC and fouling.SRP-LR Section 3.3.2.2.9 states that loss of material due to general, pitting, and crevicecorrosion, MIC, and fouling may occur in steel heat exchanger components exposed to lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of lubricating oil programs. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated in the LRA that loss of material due to general, pitting, crevice, MICand fouling for carbon steel heat exchanger components exposed to lubricating oil are an AERM in the auxiliary systems, and is managed by the Oil Analysis Program. This program includes periodic sampling and analysis of lubricating oil to maintain 3-309contaminants within acceptable limits, thereby preserving an environment that is notconducive to corrosion or fouling. Operating experience has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion and fouling has not and will not affect the intended functions of these components.The staff determines that Oil Analysis Program alone is not sufficient in managing theloss of material of steel heat exchanger components exposed to lubricating oil. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA is revised to state the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program.The staff finds that, based on the programs and LRA review identified above, theapplicant has met the criteria of SRP-LR Section 3.3.2.2.9. Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.3.2.2.9 criteria. For those line items that apply to LRA Section 3.3.2.2.9, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.2.10  Loss of Material Due to Pitting and Crevice Corrosion The staff reviewed LRA Section 3.3.2.2.10 against the following SRP-LR Section 3.3.2.2.10criteria:  (1)LRA Section 3.3.2.2.10 addresses loss of material from steel piping with elastomer liningor stainless steel cladding due to pitting and crevice corrosion is not applicable toVYNPS. Loss of material due to pitting and crevice corrosion could occur in BWR and PWR steel piping with elastomer lining or stainless steel cladding that are exposed totreated water and treated borated water if the cladding or lining is degraded. For the auxiliary systems at VYNPS no credit is taken for any elastomer linings or stainless steel cladding to prevent loss of material from the underlying carbon steel material such that the material is identified as carbon steel for the AMR.SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevicecorrosion may occur in BWR and PWR steel piping with elastomer lining or stainless steel cladding exposed to treated water and treated borated water if the cladding or lining is degraded. The existing AMP monitors and controls reactor water chemistry to manage the aging effects of loss of material from pitting and crevice corrosion. However, high concentrations of impurities in crevices and with stagnant flow conditions may cause pitting or crevice corrosion; therefore, the effectiveness of water chemistry control programs should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage loss of material from pitting and crevice corrosion to verify the effectiveness of water chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.
3-310The applicant was asked in RAI 3.3.1-22-K-01 to confirm that no auxiliary componentshave elastomer linings or stainless steel cladding. If there are such components, to provide a list of these components. The applicant was also asked to provide additional justification for the determination that pitting and crevice corrosion do not require aging management.In a letter dated September 5, 2006, the applicant provided its response toRAI 3.3.1-22-K-01. The applicant stated that elastomer linings are conservatively not credited to prevent loss of material of underlying carbon steel material in auxiliary systems. Furthermore, the applicant stated that in LRA Section 3.3.2.2.7, loss of material due to general, pitting, and crevice corrosion in carbon steel piping and components in auxiliary systems exposed to treated water in managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program. The staff reviewed the applicant's response and finds it acceptable. The staff alsoconfirmed that steel piping with elastomer lining is managed in accordance with the component group of carbon steel piping and components. Further, the staff's concern described in RAI 3.3.1-22-K-01 is resolved.On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS. The staff finds that, based on the programs identified above, the applicant has met thecriteria of SRP-LR Section 3.3.2.2.10.    (2)LRA Section 3.3.2.2.10 addresses the loss of material of stainless steel piping andcomponents and stainless steel heat exchanger components exposed to treated water due to pitting and crevice corrosion.SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevicecorrosion may occur in stainless steel and aluminum piping, piping components, pipingelements, and for stainless steel and steel with stainless steel cladding heat exchangercomponents exposed to treated water. The existing AMP monitors and controls reactor water chemistry to manage the aging effects of loss of material from pitting and crevice corrosion. However, high concentrations of impurities in crevices and with stagnant flow conditions may cause pitting or crevice corrosion; therefore, the effectiveness of water chemistry control programs should be verified to ensure that corrosion does not occur.
The GALL Report recommends further evaluation of programs to manage loss of material from pitting and crevice corrosion to verify the effectiveness of water chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated in the LRA that in the auxiliary systems at VYNPS there are noaluminum components exposed to treated water. Loss of material due to pitting and crevice corrosion for stainless steel piping and components, and for stainless steel heatexchanger components exposed to treated water in the auxiliary systems at VYNPS is 3-311managed by the Water Chemistry Control-BWR Program. The effectiveness of theprogram will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow.The staff reviewed the applicant's Water Chemistry Control-BWR Program andOne-Time Inspection Program. The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. This combination satisfies the criteria of SRP-LR Appendix A.1 and therefore is acceptable.The staff finds that, based on the programs identified above, the applicant has met thecriteria of SRP-LR Section 3.3.2.2.10.    (3)LRA Section 3.3.2.2.10 addresses the loss of material of copper alloy componentsexposed to condensation (external) in the HVAC and other auxiliary systems due to pitting and crevice corrosion.SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevicecorrosion may occur in copper alloy HVAC piping, piping components, and pipingelements exposed to condensation (external). The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed.The applicant stated in the LRA that loss of material due to pitting and crevice corrosionfor copper alloy components exposed to condensation (external) in the HVAC and other auxiliary systems is managed by the System Walkdown Program, the Periodic Surveillance and Preventive Maintenance Program, the Service Water Integrity Program, and the Heat Exchanger Monitoring Program. The applicant's System Walkdown Program includes a periodic visual inspection. The applicant's Periodic Surveillance and Preventive Maintenance Program, Service Water Integrity Program and the Heat Exchanger Monitoring Program include other NDE techniques to manage loss of material of the components. These inspections will manage the aging effect of loss of material such that the intended function of the components will not be affected.The staff evaluated each auxiliary system AMR associated with copper alloy componentsexposed to condensation. The application of programs that are not plant-specific was discussed with the applicant's technical personnel. In each case, the staff finds that an appropriate program had been identified for monitoring loss of material due to pitting and crevice corrosion.The staff finds that, based on the programs identified above, the applicant has met thecriteria of SRP-LR Section 3.3.2.2.10.
3-312  (4)LRA Section 3.3.2.2.10 addresses the loss of material of copper alloy componentsexposed to lubricating oil due to pitting and crevice corrosion.SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevicecorrosion may occur in copper alloy piping, piping components, and piping elementsexposed to lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of lubricating oil programs. A one-time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated in the LRA that loss of material due to pitting and crevice corrosionfor copper alloy components exposed to lubricating oil in auxiliary systems is managed by the Oil Analysis Program, which includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. Operating experience has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion has not and will not affect the intended functions of these components.During the audit and review, the staff determines that the applicant's Oil AnalysisProgram alone is not sufficient in managing the loss of material of copper alloy piping, piping components, and piping elements exposed to lubricating oil. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program.The staff determines that, based on the programs identified above, the applicant has metthe criteria of SRP-LR Section 3.3.2.2.10.  (5)LRA Section 3.3.2.2.10 addresses the loss of material of HVAC aluminum piping, pipingcomponents, and piping elements and stainless steel ducting and components exposed to condensation due to pitting and crevice corrosion.SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevicecorrosion may occur in HVAC aluminum piping, piping components, and piping elementsand stainless steel ducting and components exposed to condensation. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed.The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosioncould occur for HVAC aluminum piping, piping components, and piping elements andstainless steel ducting and components exposed to condensation. At VYNPS, there are no aluminum components or stainless steel ducting exposed to condensation in the 3-313HVAC systems. However, this item can be applied to stainless steel componentsexposed to condensation, both internal and external, in other systems. The System Walkdown Program, and the Service Water Integrity Program, will manage loss of material in stainless steel components exposed externally to condensation. The Periodic Surveillance and Preventive Maintenance Program, will manage loss of material in stainless steel components exposed internally or externally to condensation. These programs include a periodic visual inspection and the Periodic Surveillance and Preventive Maintenance Program includes other NDE techniques to manage loss of material of the components.The staff evaluated each auxiliary system AMR associated with stainless steelcomponents exposed to condensation. The application of programs that are not plant-specific was discussed with the applicant's technical personnel. In each case, the staff finds that an appropriate program had been identified for monitoring loss of material due to pitting and crevice corrosion.The staff finds that, based on the programs identified above, the applicant has met thecriteria of SRP-LR Section 3.3.2.2.10.  (6)LRA Section 3.3.2.2.10 addresses the loss of material of copper alloy fire protectionsystem piping, piping components, and piping elements exposed to internal condensationdue to pitting and crevice corrosion.SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevicecorrosion may occur in copper alloy fire protection system piping, piping components, and piping elements exposed to internal condensation. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed.The applicant stated in the LRA that loss of material due to pitting and crevice corrosioncould occur for copper alloy fire protection system piping, piping components, and pipingelements exposed to internal condensation. At VYNPS, there are no copper alloy components exposed to condensation in the fire protection systems. However, this item can be applied to copper alloy components exposed to internal condensation in other systems.The Periodic Surveillance and Preventive Maintenance Program, will manage loss ofmaterial in copper alloy components exposed internally to untreated air, which is equivalent to condensation, through the use of visual inspections or other NDE techniques.The Instrument Air Quality Program, will manage loss of material in copper alloycomponents exposed internally to treated air. The applicant's Instrument Air Quality Program maintains humidity and particulates within acceptable limits, thereby preserving the environment of treated air that is not conducive to corrosion. This is equivalent to the management of loss of material in steel and stainless steel components addressed in LRA Table 3.3.1, Items 3.3.1-53 and 3.3.1-54, respectively.
3-314The staff evaluated each auxiliary system AMR associated with copper alloy componentsexposed to condensation. The staff finds that the Periodic Surveillance and Preventive Maintenance Program would be an appropriate, plant-specific program for monitoring loss of material (copper) due to pitting and crevice corrosion. The staff finds that the plant-specific Instrument Air Quality Program served to prevent condensation from forming inside the IA system. Also by reviewing the implementing procedures for measuring dewpoint, particulate concentration and hydrocarbon concentration monitoring, the staff noted that a degradation of the piping and any components would become evident by excessive corrosion or by failure of the system or of any components to meet specified performance limits (see SER Section 3.0.3.3.4.1.4). The staff finds that the Instrument Air Quality Program would be an appropriate plant-specific program monitoring loss of material due to pitting and crevice corrosion.The staff finds that, based on the programs identified above, the applicant has met thecriteria of SRP-LR Section 3.3.2.2.10.  (7)LRA Section 3.3.2.2.10 addresses the loss of material of stainless steel piping, pipingcomponents, and piping elements exposed to soil due to pitting and crevice corrosion.SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevicecorrosion may occur in stainless steel piping, piping components, and piping elementsexposed to soil. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed.The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosioncould occur for stainless steel piping, piping components, and piping elements exposedto soil. At VYNPS, there are no stainless steel piping components exposed to soil in the auxiliary systems. However, loss of material due to pitting and crevice corrosion for stainless steel bolting buried in soil in the fire protection-water systems is managed by the Buried Piping Inspection Program. This program will include: (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the buried stainless steel bolting.The applicant also stated that buried components are to be inspected when excavatedduring maintenance. An inspection will be performed within 10 years of entering the period of extended operation, unless an opportunistic inspection occurs within this 10-year period. This program will manage the aging effect of loss of material such that the intended function of the components will not be affected.During the audit and review, the staff confirmed that buried piping has already beeninspected within the final 10-year period before the period of extended operation.
Therefore, even if no other buried piping is examined before the period of extended operation, VYNPS has complied with staff guidance regarding the examination of buried piping before the end of the current operating license. The staff finds that the proposed schedule for inspection (if there is no other opportunity) is consistent with the staff's guidance and therefore acceptable.
3-315The staff finds that, based on the programs identified above, the applicant has met thecriteria of SRP-LR Section 3.3.2.2.10.  (8)LRA Section 3.3.2.2.10 addresses loss of material of stainless steel piping andcomponents of the SLC system exposed to sodium pentaborate solution due to pitting and crevice corrosion.SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevicecorrosion may occur in stainless steel piping, piping components, and piping elements ofthe BWR SLC system exposed to sodium pentaborate solution. The existing AMP monitors and controls water chemistry to manage the aging effects of loss of material due to pitting and crevice corrosion. However, high concentrations of impurities in crevices and with stagnant flow conditions may cause loss of material due to pitting and crevice corrosion; therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that this aging does not occur. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that loss of material due to pitting and crevice corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosionfor stainless steel piping and components of the SLC system exposed to sodium pentaborate solution is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicant's Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow. The staff determines this combination satisfies the criteria of SRP-LR Appendix A.1 and therefore is acceptable.The staff finds this to be consistent with the criteria of SRP-LR Section 3.3.2.2.10 andtherefore acceptable.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.3.2.2.10 criteria. For those line items that apply to LRA Section 3.3.2.2.10, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.2.11  Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion The staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR Section 3.3.2.2.11.
LRA Section 3.3.2.2.11 addresses the loss of material of copper alloy piping and componentsexposed to treated water in the auxiliary and other systems due to pitting and crevice, and galvanic corrosion.
 
3-316SRP-LR Section 3.3.2.2.11 states that loss of material due to pitting, crevice, and galvaniccorrosion may occur in copper alloy piping, piping components, and piping elements exposed totreated water. Therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that this aging does not occur. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that loss of material due to pitting and crevice corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated, in the LRA, that loss of material due to pitting and crevice, and galvaniccorrosion for copper alloy piping and components exposed to treated water in the auxiliary and other systems is managed by the Water Chemistry Control-BWR Program. The effectiveness of the program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow. The staff determines this combination satisfies the criteria of SRP-LR Appendix A.1 and therefore is acceptable.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.3.2.2.11 criteria. For those line items that apply to LRA Section 3.3.2.2.11, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.2.12  Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion The staff reviewed LRA Section 3.3.2.2.12 against the following SRP-LR Section 3.3.2.2.12criteria:  (1)LRA Section 3.3.2.2.12 addresses the loss of material of stainless steel, aluminum andcopper alloy piping, and components exposed to fuel oil due to pitting, crevice, and MIC.SRP-LR Section 3.3.2.2.12 states that loss of material due to pitting and crevicecorrosion, and MIC may occur in stainless steel, aluminum, and copper alloy piping,piping components, and piping elements exposed to fuel oil. The existing AMP relies on the fuel oil chemistry program for monitoring and control of fuel oil contamination to manage loss of material due to corrosion; however, corrosion may occur at locations where contaminants accumulate and the effectiveness of fuel oil chemistry control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of the fuel oil chemistry control program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated, in the LRA, that loss of material due to pitting, crevice, and MIC instainless steel, aluminum and copper alloy piping, and components exposed to fuel oil isan AERM and these components are managed by the Diesel Fuel Monitoring Program.
This program includes sampling and monitoring of fuel oil quality to ensure they remain 3-317within the limits specified by the ASTM standards. Maintaining parameters within limitsensures that significant loss of material will not occur. Operating experience has confirmed the effectiveness of this program in maintaining fuel oil quality within limits such that loss of material will not affect the intended functions of these components.The staff finds that the applicant's Diesel Fuel Monitoring Program alone is not sufficientin managing the loss of material of stainless steel, aluminum and copper alloy piping, andcomponents exposed to lubricating oil due to pitting, crevice, and MIC. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program verifies the effectiveness of the Diesel Fuel Monitoring Program.The staff finds that, based on the programs identified above, the applicant has met thecriteria of SRP-LR Section 3.3.2.2.12.  (2)LRA Section 3.3.2.2.12 addresses loss of material of stainless steel piping andcomponents exposed to lubricating oil due to pitting, crevice, and MIC. SRP-LR Section 3.3.2.2.12 states that loss of material due to pitting and crevicecorrosion, and MIC may occur in stainless steel piping, piping components, and pipingelements exposed to lubricating oil. The existing program periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of lubricating oil programs. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated in the LRA that loss of material due to pitting, crevice, and MIC instainless steel piping and components exposed to lubricating oil is managed by the Oil Analysis Program, which includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. Operating experience has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion has not and will not affect the intended functions of these components.The staff finds that Oil Analysis Program alone is not sufficient in managing the loss ofmaterial of stainless steel piping and components exposed to lubricating oil due to pitting,crevice, and MIC. In a letter dated July 14, 2006, the applicant amended the its LRA. The applicant stated that LRA is revised to state the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program.
3-318The staff finds that, based on the programs identified above, the applicant has met thecriteria of SRP-LR Section 3.3.2.2.13.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.3.2.2.12 criteria. For those line items that apply to LRA Section 3.3.2.2.12, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.2.13  Loss of Material Due to Wear The staff reviewed LRA Section 3.3.2.2.13 against the criteria in SRP-LR Section 3.3.2.2.13.
LRA Section 3.3.2.2.13 addresses the loss of material due to wear, this aging effect is notapplicable to VYNPS. Loss of material due to wear could occur in the elastomer seals and components exposed to air indoor uncontrolled (internal or external). At VYNPS, in the auxiliary systems, this specific aging effect for elastomers is not applicable based on operating experience. Where the aging effects of change in material properties and cracking are identified for elastomer components, they are managed by the Periodic Surveillance and Preventive Maintenance Program. This item is not applicable to VYNPS auxiliary systems.SRP-LR Section 3.3.2.2.13 states that loss of material due to wear may occur in the elastomerseals and components exposed to air-indoor uncontrolled (internal or external). The GALL Report recommends further evaluation to ensure that these aging effects are adequately managed.During the audit and review, the staff finds that operating experience provided an insufficientbasis for determining that this aging mechanism is not applicable at VYNPS. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant revised LRA Section 3.3.2.2.13 to state: Wear is the removal of surface layers due to relative motion between twosurfaces. At VYNPS, in the auxiliary systems, this specific aging effect is not applicable because the HVAC elastomer coated fiberglass duct flexible connections are fixed at both ends, precluding wear. This item is not applicable to VYNPS auxiliary systems.The staff finds that wear is precluded by the system design feature.
On this basis that this aging effect/mechanism is not applicable to VYNPS auxiliary systems, thestaff finds that this aging effect is not applicable to VYNPS.
3-319Based on the program identified above, the staff concludes that the applicant's program meetsSRP-LR Section 3.3.2.2.13 criteria. For those line items that apply to LRA Section 3.3.2.2.13, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.2.14  Loss of Material Due to Cladding Breach The staff reviewed LRA Section 3.3.2.2.14 against the criteria in SRP-LR Section 3.3.2.2.14.
LRA Section 3.3.2.2.14 addresses the cracking due to underclad cracking, which could occur forPWR steel charging pump casings with stainless steel cladding exposed to treated boratedwater. As VYNPS is a BWR and has no charging pumps. This item is not applicable to VYNPSSRP-LR Section 3.3.2.2.14 states that loss of material due to cladding breach may occur inPWR steel charging pump casings with stainless steel cladding exposed to treated boratedwater. The GALL Report references IN 94-63 and recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed.The staff confirmed that VYNPS has no components from this group.
On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.3.3.2.2.15  Quality Assurance for Aging Management of Nonsafey-Related Components SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.
 
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determines that the applicant adequately addressed the issues that were further evaluated. The staff finds that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3  AMR Results Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.3.2-1 through 3.3.2-12and Tables 3.3.2-13-1 through 3.3.2-13-58, the staff reviewed additional details of the AMR results for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report. These items were reviewed and they are further addressed in SER Section 3.3.2.3.In LRA Tables 3.3.2-1 through 3.3.2-12 and Tables 3.3.2-13-1 through 3.3.2-13-58, the applicantindicated, via notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided 3-320further information about how it will manage the aging effects. Specifically, note F indicates thatthe material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.Staff Evaluation. For component type, material, and environment combinations not evaluated inthe GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff's evaluation is documented in the following sections.3.3.2.3.1  Standby Liquid Control System Summary of Aging Management Evaluation - LRATable 3.3.2-1The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for theSLC system component groups.The staff finds that all AMR evaluation results in LRA Table 3.3.2-1 are consistent with the GALLReport.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.2  Service Water Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-2The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for theSWSs component groups.In LRA Table 3.3.2-2, the applicant proposed to manage loss of material due to wear ofcopper-alloy heat exchanger tubes exposed to condensation and stainless steel heat exchanger tubes exposed to treated water and using the Service Water Integrity Program.The staff reviewed the applicant's Service Water Integrity Program and Its evaluation isdocumented in SER Section 3.0.3.2.16. The applicant's Service Water Integrity Program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the SWS will be managed for the period of extended operation. On this basis, the staff finds the loss of copper alloy due to wear when exposed to condensation is adequately managed using the Service Water Integrity Program.
3-321In LRA Table 3.3.2-2, the applicant proposed to manage loss of material from stainless steelvalve bodies exposed to outdoor air using the System Walkdown Program.The staff reviewed the applicant's System Walkdown Program, which entails inspections ofexternal surfaces of components subject to an AMR. The staff's evaluation is documented in SER Section 3.0.3.1.9. The System Walkdown Program includes inspections of external surfaces of components and is consistent with the program described in GALL AMP XI.M36, "External Surfaces Monitoring." On this basis, the staff finds loss of material of stainless steel from valve bodies exposed to air is adequately managed using the System Walkdown Program.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.3  Reactor Building Closed Cooling Water System Summary of Aging ManagementEvaluation - LRA Table 3.3.2-3The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for theRBCCW system component groups.In LRA Table 3.3.2-3, the applicant proposed to manage loss of material due to wear of carbonsteel heat exchanger tubes exposed to untreated water, copper alloy heat exchanger tubes exposed to lubricating oil or condensation, and stainless steel heat exchanger tubes exposed to treated water or indoor air using the Heat Exchanger Monitoring Program.The staff reviewed the applicant's Heat Exchanger Monitoring Program and its evaluation isdocumented in SER Section 3.0.3.3.1. Heat exchanger monitoring program will inspect the heat exchangers for degradation. Eddy current inspections will be performed, where practical, to determine heat exchanger tube wall thickness. These inspections are to ensure that effects of aging are identified prior to loss of intended function. On this basis, the staff finds loss of material from carbon steel heat exchanger tubes exposed to untreated water, copper alloy heat exchanger tubes exposed to lubricating oil or condensation, and stainless steel heat exchanger tubes exposed to treated water or indoor air is adequately managed using the Heat Exchanger Monitoring ProgramOn this basis, the staff finds that management of loss of material due to wear in the RBCCWsystem is acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-3223.3.2.3.4  Emergency Diesel Generator System Summary of Aging ManagementEvaluation-LRA Table 3.3.2-4The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for theEDG system component groups.In LRA Table 3.3.2-4, the applicant proposed to manage cracking of stainless steel strainersexposed to a lubricating oil environment using the Oil Analysis Program. In a letter dated July 14, 2006, the applicant amended the LRA so that the One-Time Inspection Program, verified the effectiveness of the Oil Analysis Program.The staff reviewed the applicant's Oil Analysis Program, which is a monitoring program thatmaintains oil systems free of contaminants (primarily water and particulates) thereby preserving an environment that is not conducive to loss of material, cracking, or fouling. The staff also reviewed the applicant's One-Time Inspection Program, which confirms the effectiveness of the Oil Analysis Program. The staff's evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. Because the Oil Analysis Program has maintained VYNPS oil systems free of contaminants and the effectiveness of the program will be confirmed by the One-Time Inspection Program, the staff finds that the cracking of stainless steel strainers exposed to lubricating oil is adequately managed using the Oil Analysis Program and the One-Time Inspection Program.On this basis, the staff finds that management of cracking in the EDG system is acceptable.
In LRA Table 3.3.2-4, the applicant proposed to manage fatigue damage to stainless steelexpansion joints as well as carbon steel expansion joints, piping, silencers, and turbochargers exposed to exhaust gas using TLAA.The staff's review of this TLAA evaluation is documented in SER Section 4.3.
In LRA Table 3.3.2-4, the applicant proposed to manage fouling of aluminum heat exchanger(fins) and copper-alloy heat exchanger (tubes) using the Periodic Surveillance and Preventive Maintenance Program.The staff reviewed the Periodic Surveillance and Preventive Maintenance Program. Itsevaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1.This program that includes periodic inspections and tests that manage aging effects not managed by other AMP s. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. On this basis, the staff finds that fouling of aluminum heat exchanger fins and copper alloy tubes when exposed to air is adequately managed using the Periodic Surveillance and Preventive Maintenance Program.In LRA Table 3.3.2-4, the applicant proposed to manage loss of material due to wear ofcopper-alloy heat exchanger tubes exposed to lubricating oil or treated water using the Service Water Integrity Program.
3-323The staff reviewed the Service Water Integrity Program and its evaluation is documented in SERSection 3.0.3.2.16. The program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the SWSs will be managed for the period of extended operation. On this basis, the staff finds loss of copper alloy due to wear when exposed to treated water is adequately managed using the Service Water Integrity Program.In LRA Table 3.3.2-4, the applicant proposed to manage loss of material due to wear ofcopper-alloy heat exchanger tubes exposed to indoor air using the Periodic Surveillance and Preventive Maintenance Program.The staff reviewed the Periodic Surveillance and Preventive Maintenance Program and itsevaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. This program includes periodic inspections and tests that manage aging effects not managed by other AMPs. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. On this basis, the staff finds that loss of material from copper alloy tubes exposed to indoor air is adequately managed using the Periodic Surveillance and Preventive Maintenance Program.In LRA Table 3.3.2-4, the applicant proposed to manage loss of material from stainless steelstrainers exposed to outdoor air using the System Walkdown Program.The staff reviewed the applicant's System Walkdown Program, which entails inspections ofexternal surfaces of components subject to an AMR. The staff's evaluation is documented in SER Section 3.0.3.1.9. The System Walkdown Program includes inspections of external surfaces of components and is consistent with the program described in GALL AMP XI.M36, "External Surfaces Monitoring." On this basis, the staff finds loss of stainless steel from strainers exposed to air is adequately managed using the System Walkdown Program.On the basis of its review, the staff finds that the applicant appropriately evaluated the AMRresults involving material, environment, AERM, and AMP combinations that are not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.5  Fuel Pool Cooling Systems Summary of Aging Management Evaluation -LRATable 3.3.2-5The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for thefuel pool cooling systems component groups.In LRA Table 3.3.2-5, the applicant proposed to manage cracking of aluminum/boron carbidematerial for neutron absorber (boral) component types exposed to treated water using the Water Chemistry Control - BWR Program.The staff's evaluation of the Water Chemistry Control - BWR Program is documented in SERSection 3.0.3.1.11. This program is consistent with GALL AMP XI.M2, "Water Chemistry." On the basis of its review, the staff found that, because the water chemistry will be monitored 3-324periodically and controlled within established levels of contaminants, the aging effect of crackingof aluminum/boron carbide neutron absorber (boral) components exposed to treated water will be effectively managed by the Water Chemistry Control - BWR Program.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.6  Fuel Oil System Summary of Aging Management Evaluation-LRA Table 3.3.2-6 The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for thefuel oil system component groups.In LRA Table 3.3.2-6, the applicant proposed to manage loss of material from carbon steel tanksexposed to concrete using the Diesel Fuel Monitoring Program. In a letter dated July 14, 2006, the applicant amended the LRA so that the One-Time Inspection Program, verified the effectiveness of the Diesel Fuel Monitoring Program.The staff reviewed the applicant's Diesel Fuel Monitoring Program. The staff also reviewed theapplicant's One-Time Inspection Program, which confirms the effectiveness of the Diesel Fuel Monitoring Program. The staff's evaluations are documented in SER Sections 3.0.3.2.9 and 3.0.3.1.6, respectively. The Diesel Fuel Monitoring Program entails sampling to ensure that adequate diesel fuel quality is maintained to prevent corrosion of fuel systems. Exposure to fuel oil contaminants such as water and microbiological organisms is minimized by periodic drainingand cleaning of tanks and by verifying the quality of new oil before its introduction into storage tanks. On this basis, the staff finds the loss of material from carbon-steel tanks is adequately managed using the Diesel Fuel Monitoring Program and the One-Time Inspection Program.In LRA Table 3.3.2-6, the applicant proposed to manage cracking of stainless steel flex hosesexposed to fuel oil using the Diesel Fuel Monitoring Program. In a letter dated July 14, 2006, the applicant amended the LRA so that applicant's One-Time Inspection Program verified the effectiveness of its Diesel Fuel Monitoring Program.The staff reviewed the applicant's Diesel Fuel Monitoring Program. The staff also reviewed theapplicant's One-Time Inspection Program, which confirms the effectiveness of the Diesel Fuel Monitoring Program. The staff's evaluations are documented in SER Sections 3.0.3.2.9 and 3.0.3.1.6, respectively. The Diesel Fuel Monitoring Program entails sampling to ensure that adequate diesel fuel quality is maintained to prevent corrosion of fuel systems. Exposure to fuel oil contaminants such as water and microbiological organisms is minimized by periodic drainingand cleaning of tanks and by verifying the quality of new oil before its introduction into storage tanks. On this basis, the staff finds the cracking of stainless steel flex houses is adequately managed using the Diesel Fuel Monitoring Program and the One-Time Inspection Program.
3-325On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.7  Instrument Air System Summary of Aging Management Evaluation-LRA Table 3.3.2-7 The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for theIA system component groups. The staff determines that all AMR evaluation results in LRA Table 3.3.2-7 are consistent with theGALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.8  Fire Protection - Water System Summary of Aging Management Evaluation-LRATable 3.3.2-8The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for thefire protection-water system component groups.In LRA Table 3.3.2-8, the applicant proposed to manage cracking of stainless steel valve bodiesexposed to treated water using the Fire Protection Program.The staff reviewed the applicant's Fire Protection Program, which includes a fire barrierinspection and a diesel-driven fire pump inspection. The staff's evaluation is documented in SER Section 3.0.3.2.11. The Fire Protection Program includes periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire rated doors to ensure that their operability is maintained. The diesel-driven fire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. On this basis, the staff finds that cracking of stainless steel valve bodies exposed to treated water is adequately managed using the Fire Protection Program.In LRA Table 3.3.2-8, the applicant proposed to manage fatigue damage to carbon steel piping,silencer, and turbocharger as well as a stainless steel expansion joint exposed to exhaust gases and copper-alloy heat exchanger tubes as well as carbon steel heat exchanger (bonnet) and piping exposed to lubricating oil using the Fire Protection Program.The staff reviewed the applicant's Fire Protection Program, which includes a fire barrierinspection and a diesel-driven fire pump inspection. The staff's evaluation is documented in SER Section 3.0.3.2.11. The Fire Protection Program requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and 3-326functional tests of fire rated doors to ensure that their operability is maintained. The diesel-drivenfire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. On this basis, the staff determines that cracking due to fatigue of carbon steel piping, silencer, and turbocharger as well as a stainless steel expansionjoint exposed to exhaust gases and copper-alloy heat exchanger tubes as well as carbon steel heat exchanger (bonnet) and piping exposed to lubricating oil is adequately managed using the Fire Protection Program. On this basis, the staff finds that management of cracking in the fire protection water system is acceptable.In LRA Table 3.3.2-8, the applicant proposed to manage fouling of copper-alloy heat exchangertubes exposed to treated water using the Fire Protection Program.The staff reviewed the applicant's Fire Protection Program, which includes a fire barrierinspection and a diesel-driven fire pump inspection. The staff's evaluation is documented in SER Section 3.0.3.2.11. The Fire Protection Program requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire rated doors to ensure that their operability is maintained. The diesel-driven fire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. On this basis, the staff finds that fouling of the copper-alloy heat exchanger tubes exposed to treated water is adequately managed using the Fire Protection Program.On this basis, the staff finds that management of fouling in the fire protection system isacceptable.In LRA Table 3.3.2-8, the applicant proposed to manage loss of material from aluminum heaterhousing; carbon steel filter housing, heat exchanger shell, piping, pump casing, and valve bodies; copper-alloy heat exchanger tubes, tubing, and valve bodies; as well as stainless steel valve bodies exposed to treated water using the Fire Protection Program.The staff reviewed the applicant's Fire Protection Program, which includes a fire barrierinspection and a diesel-driven fire pump inspection. The staff's evaluation is documented in SER Section 3.0.3.2.11. The Fire Protection Program requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire rated doors to ensure that their operability is maintained. The diesel-driven fire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. On this basis, the staff finds that loss of material from aluminum heater housing; carbon steel filter housing, heat exchanger shell, piping, pump casing, and valve bodies; copper-alloy heat exchanger tubes, tubing, and valve bodies; as well as stainless steel valve bodies exposed to treated water is adequately managed using the Fire Protection Program.In LRA Table 3.3.2-8, the applicant proposed to manage loss of material from carbon steel flownozzle, piping, tank, and valve bodies; copper-alloy flow nozzles and valve bodies; as well as gray cast iron valve bodies exposed to fire protection foam using the Fire Water System Program.
3-327The staff reviewed the applicant's Fire Water System Program and its evaluation is documentedin SER Section 3.0.3.2.12. The Fire Water System Program applies to water-based fire protection systems that consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes, and aboveground and underground piping and components that are tested in accordance with applicable NFPA codes and standards. On this basis, the staff finds that loss of material from carbon steel flow nozzle, piping, tank, and valve bodies; copper-alloy flow nozzles and valve bodies; as well as gray cast iron valve bodies exposed to fire protection foam is adequately managed using the Fire Water System Program.In LRA Table 3.3.2-8, the applicant proposed to manage selective leaching of copper-alloy flownozzles and valve bodies and gray cast iron valve bodies exposed to fire protection foam using the Selective Leaching Program.The staff reviewed the applicant's Selective Leaching Program, which ensures the integrity ofcomponents made of cast iron, bronze, brass, and other alloys exposed to raw water, treated water, or groundwater that may lead to selective leaching. The staff's evaluation is documented in SER Section 3.0.3.1.7. The Selective Leaching Program is consistent with GALL AMP XI.M33, "Selective Leaching of Materials." On this basis, the staff finds the selective leaching of material from copper-alloy flow nozzles and valve bodies and gray cast iron valve bodies exposed to fire protection foam is adequately managed using the Selective Leaching Program.In LRA Table 3.3.2-8, the applicant proposed to manage loss of material from stainless steelbolting and copper alloy nozzles exposed to outdoor air using the System Walkdown Program.The staff reviewed the applicant's System Walkdown Program, which entails inspections ofexternal surfaces of components subject to an AMR. The staff's evaluation is documented in SER Section 3.0.3.1.9. The staff determines the loss of material from stainless steel bolting andcopper alloy nozzles exposed to outdoor air is adequately managed using the System Walkdown Program.The applicant also committed (Commitment #34) to a Bolting Integrity Program consistent withGALL AMP XI.M18, "Bolting Integrity." The staff's evaluation is documented in SER Section 3.0.3.2.19. The program applies to bolting and torquing practices of safety-related and nonsafety-related carbon and stainless steel bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all safety and nonsafety-relates bolting regardless of size (except the reactor vessel closure studs which are address by the Reactor Vessel Closure Studs Program) and material. On this basis, the staff finds that management of loss of material in the fire protection water system is acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-3283.3.2.3.9  Fire Protection - CO 2 System Summary of Aging Management Evaluation - LRATable 3.3.2-9The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for thefire protection - CO 2 system component groups.In LRA Table 3.3.2-9, the applicant proposed to manage loss of material from copper alloypiping, tubing, and valve bodies and stainless steel bolting, orifices, tubing, and valve bodiesexposed to outdoor air using the System Walkdown Program.The staff reviewed the applicant's System Walkdown Program, which entails inspections ofexternal surfaces of components subject to an AMR. The staff's evaluation is documented in SER Section 3.0.3.1.9. The System Walkdown Program includes inspections of external surfaces of components subject to an AMR. On this basis, the staff finds the loss of material from copper alloy piping, tubing, and valve bodies and stainless steel bolting, orifices, tubing,and valve bodies exposed to outdoor air is adequately managed using the System Walkdown Program. The applicant also committed (Commitment #34) to a Bolting Integrity Program consistent withGALL AMP XI.M18, "Bolting Integrity." The staff's evaluation is documented in SER Section 3.0.3.2.19. The program applies to bolting and torquing practices of safety-related and nonsafety-related carbon and stainless steel bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all safety and nonsafety-relates bolting regardless of size (except the reactor vessel closure studs which are address by the Reactor Vessel Closure Studs Program) and material. On this basis, the staff finds that management of loss of material in the fire protection CO 2 system is acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.10  Heating, Ventilation, and Air Conditioning Systems Summary of Aging ManagementEvaluation - LRA Table 3.3.2-10The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations forthe HVAC systems component groups.In LRA Table 3.3.2-10, the applicant proposed to manage fouling of copper alloy heat exchangertubes exposed to condensation using the Periodic Surveillance and Preventive Maintenance Program.The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Programand its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. This Program includes periodic inspections and tests that manage aging effects not managed by other AMP s. The preventive maintenance and surveillance testing 3-329activities are generally implemented through repetitive tasks or routine monitoring of plantoperations. On this basis, the staff finds fouling of copper alloy heat exchanger tubes exposed to condensation is adequately managed using the Periodic Surveillance and Preventive Maintenance Program.In LRA Table 3.3.2-10, the applicant proposed to manage fouling of aluminum heat exchangerfins and fouling of copper-alloy heat exchanger tubes exposed to condensation using the Service Water Integrity Program.The staff reviewed the applicant's Service Water Integrity Program and its evaluation isdocumented in SER Section 3.0.3.2.16. The Service Water Integrity Program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the SWSs will be managed for the period of extended operation. On this basis, the staff finds fouling of aluminum heat exchanger fins as well as fouling of copper-alloy heat exchanger tubes exposed to condensation is adequately managed using the Service Water Integrity Program. On this basis, the staff finds that management of fouling in the HVAC system is acceptable.In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due to wear of copperalloy heat exchanger tubes exposed to condensation or treated water using the Periodic Surveillance and Preventive Maintenance Program.The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Programand its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. This program includes periodic inspections and tests that manage aging effects not managed by other AMPs. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. On this basis, the staff finds loss of material due to wear of copper alloy heat exchanger tubes exposed to condensation or treated water is adequately managed using the Periodic Surveillance and Preventive Maintenance Program.In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due to wear ofcopper-alloy heat exchanger tubes exposed to condensation using the Service Water Integrity Program.The staff reviewed the applicant's Service Water Integrity Program and its evaluation isdocumented in SER Section 3.0.3.2.16. The Service Water Integrity Program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the SWSs will be managed for the period of extended operation. On this basis, the staff finds loss of material due to wear of copper-alloy heat exchanger tubes exposed to condensation is adequately managed using the Service Water Integrity Program.In LRA Table 3.3.2-10, the applicant proposed to manage loss of material from aluminumdamper, fan, and louver housings; copper-alloy tubing and valve bodies; and stainless steel bolting exposed to outdoor air using the System Walkdown Program.
3-330The staff reviewed the applicant's System Walkdown Program and its evaluation is documentedin SER Section 3.0.3.1.9. The System Walkdown Program includes inspections of external surfaces of components subject to an AMR. The program is also credited with managing loss of material from internal surfaces, for situations in which internal and external material and environment combinations are the same such that external surface condition is representative of internal surface condition. The applicant also committed (Commitment #34) to a Bolting Integrity Program consistent with GALL AMP XI.M18, "Bolting Integrity." The staff's evaluation is documented in SER Section 3.0.3.2.19. The program applies to bolting and torquing practices of safety-related and nonsafety-related carbon and stainless steel bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all safety and nonsafety-relates bolting regardless of size (except the reactor vessel closure studs which are address by the Reactor Vessel Closure Studs Program) and material. On this basis, the staff finds that management of loss of material in the fire protection water system is acceptable. On this basis, the staff finds the loss of material from the interior and exterior of aluminum damper, fan, and louver housings; copper-alloy tubing and valve bodies; as well as from stainless steel bolting exposed to outdoor air in the HVAC system is adequately managed using the System Walkdown Program and Bolting Integrity Program.In LRA Table 3.3.2-10, the applicant proposed to manage loss of material from copper-alloy heatexchanger tubes exposed to steam using the Water Chemistry Control-Auxiliary Systems Program. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Auxiliary Systems Program.The staff reviewed the applicant's Water Chemistry Control Program for auxiliary systems andthe One-Time Inspection Program, which confirms the effectiveness of the Water Chemistry Control Program. The staff's evaluation is documented in SER Sections 3.0.3.3.7 and 3.0.3.1.6, respectively. The Water Chemistry Control Program controls contaminants at the lowest practical levels and provides corrosion protection for major systems and components. On this basis, the staff finds that loss of material from the interior of copper-alloy heat exchanger tubes exposed to steam is adequately managed using the Water Chemistry Control-Auxiliary Systems Program augmented by the One-Time Inspection Program. On this basis, the staff finds that management of loss of material in the HVAC system is acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.11  Primary Containment Atmosphere Control and Containment Atmosphere DilutionSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-11The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations forthe PCAC and containment atmosphere dilution systems component groups.
3-331In LRA Table 3.3.2-11, the applicant proposed to manage fouling of stainless steel heatexchangers exposed to indoor air using the Periodic Surveillance and Preventive Maintenance Program.The staff reviewed the Periodic Surveillance and Preventive Maintenance Program and. Itsevaluation is documented in SER Section 3.0.3.3.5.The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. This program includes periodic inspections and tests that manage aging effects not managed by other AMPs. The Periodic Surveillance and Preventive Maintenance Program visually inspect external surfaces of the hydrogen analyzer pre-cooler (heat exchanger) to manage fouling. On this basis, the staff finds fouling of stainless steel heat exchangers exposed to indoor air is adequately managed using the Periodic Surveillance and Preventive Maintenance Program. On this basis, the staff finds that management of fouling in the PCAC and containment atmosphere dilution systems is acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.12  John Deere Diesel Summary of Aging Management Evaluation-LRA Table 3.3.2-12 The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations forthe John Deere diesel component groups.In LRA Table 3.3.2-12, the applicant proposed to manage cracking due to fatigue of stainlesssteel expansion joints and the carbon steel piping, silencer, and turbocharger exposed to exhaust gases using the Periodic Surveillance and Preventive Maintenance Program.The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Programand its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. This program includes periodic inspections and tests that manage aging effects not managed by other AMP s. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. Because the program has been demonstrated to detect and control cracking due to fatigue, the staff finds cracking of stainless steel expansion joints and the carbon steel piping,silencer, and turbocharger exposed to exhaust gases is adequately managed using the Periodic Surveillance and Preventive Maintenance Program.On this basis, the staff finds that management of cracking in the John Deere Diesel isacceptable.In LRA Table 3.3.2-12, the applicant proposed to manage fouling of a copper-alloy radiatorexposed to indoor air using the Periodic Surveillance and Preventive Maintenance Program.
3-332The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Programand its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1.This program includes periodic inspections and tests that manage aging effects not managed by other AMPs. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. The staff also reviewed the applicant's operating history and industry-wide operating experience. Because the program has been demonstrated to detect and control fouling, the staff finds fouling of a copper-alloy radiator exposed to indoor air is adequately managed using the Periodic Surveillance and Preventive Maintenance Program.In LRA Table 3.3.2-12, the applicant proposed to manage fouling of a copper-alloy radiator andheat exchanger tubes exposed to treated water using the Water Chemistry Control-Auxiliary Systems Program. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Auxiliary Systems Program.The staff reviewed the applicant's Water Chemistry Control Program for auxiliary systems, whichmanages aging effects for components exposed to treated water. The staff also reviewed the applicant's One-Time Inspection Program, which confirms the effectiveness of the Water Chemistry Control Program. The staff's evaluation is documented in SER Sections 3.0.3.3.7 and 3.0.3.1.6, respectively. In addition, the staff reviewed the applicant's operating history and industry-wide operating experience. The Water Chemistry Control Program controls contaminants at the lowest practical levels and provides corrosion protection for major systems and components. On this basis, the staff finds that fouling of copper-alloy radiator and heat exchanger tubes exposed to treated water is adequately managed using the Water Chemistry Control Program-Auxiliary Systems Program augmented by the One-Time Inspection Program.
On this basis, the staff determines that management of fouling in the John Deere Diesel is acceptable.In LRA Table 3.3.2-12, the applicant proposed to manage loss of material from copper-alloyradiator and heat exchanger tubes and the carbon steel heater housings, piping, and pump casings exposed to treated water using the Water Chemistry Control-Auxiliary Systems Program, and the One-Time Inspection Program.The staff reviewed the applicant's Water Chemistry Control Program for auxiliary systems, whichmanages aging effects for components exposed to treated water. The staff also reviewed the applicant's One-Time Inspection Program, which confirms the effectiveness of the Water Chemistry Control Program. Its evaluation is documented in SER Sections 3.0.3.3.7 and 3.0.3.1.6, respectively. The Water Chemistry Control Program controls contaminants at the lowest practical levels and provides corrosion protection for major systems and components. On this basis, the staff determines that loss of material from copper-alloy radiator and heat exchanger tubes and carbon steel heater housings, piping and pump casings exposed to treated water is adequately managed using the Water Chemistry Control Program-Auxiliary Systems Program augmented by the One-Time Inspection Program.
3-333In LRA Table 3.3.2-12, the applicant proposed to manage loss of material due to wear of thecopper-alloy radiator in air and the copper-alloy heat exchanger tubes in lubricating oil using the Periodic Surveillance and Preventive Maintenance Program.The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program.Its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. This program includes periodic inspections and tests that manage aging effects not managed by other AM s. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. This program uses visual or other NDE techniques to manage loss of material. On this basis, the staff finds loss of material due to wear is adequately managed using the Periodic Surveillance and Preventive Maintenance Program. On this basis, the staff finds that management of loss of material in the John Deere Diesel is acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.13  Augmented Offgas System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-1The staff reviewed LRA Table 3.3.2-13-1, which summarized the results of AMR evaluations forthe AOG system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-1 are consistent with the GALL Reports.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.14  Condensate System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-2The staff reviewed LRA Table 3.3.2-13-2, which summarizes the results of AMR evaluations forthe condensate system component groups.In LRA Table 3.3.2-13-2, the applicant proposed to manage cracking-fatigue from carbon steelheat exchanger (shell) exposed to treated water greater than 220 F using the One-TimeInspection Program.The staff reviewed the applicant's One-Time Inspection Program and its evaluation isdocumented in SER Section 3.0.3.1.6.The One-Time Inspection Program provides assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's 3-334One-Time Inspection Program acceptable because it conforms to the recommended GALLAMP XI.M32, "One-Time Inspection" and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." On this basis, the staff finds the cracking-fatigue from carbon steel heat exchanger (shell) exposed to treated water greater than 220 F is adequatelymanaged using the One-Time Inspection Program. On this basis, the staff finds that management of cracking-fatigue in the condensate system is acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.15  Containment Air Dilution, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-3The staff reviewed LRA Table 3.3.2-13-3, which summarized the results of AMR evaluations forthe containment air dilution component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-3 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.16  Condensate Demineralizer System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-4The staff reviewed LRA Table 3.3.2-13-4, which summarized the results of AMR evaluations forthe condensate demineralizer system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-4 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.17  Control Rod Drive System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-5The staff reviewed LRA Table 3.3.2-13-5, which summarized the results of AMR evaluations forthe CRD system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-5 are consistent with the GALL Report.
3-335On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.18  Core Spray System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-6The staff reviewed LRA Table 3.3.2-13-6, which summarized the results of AMR evaluations forthe CSS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-6 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.19  Condensate Storage and Transfer System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-7The staff reviewed LRA Table 3.3.2-13-7, which summarizes the results of AMR evaluations forthe condensate storage and transfer system component groups.In LRA Table 3.3.2-13-7, the applicant proposed to manage loss of material from copper-alloytubing and stainless steel bolting exposed to outdoor air using the System Walkdown Program.The staff reviewed the applicant's System Walkdown Program and its evaluation is documentedin SER Section 3.0.3.1.9. The System Walkdown Program include inspections of external surfaces of components subject to an AMR. The program is also credited with managing loss of material from internal surfaces, for situations in which internal and external material and environment combinations are the same such that external surface condition is representative of internal surface condition. The applicant also committed (Commitment #34) to a Bolting Integrity Program consistent with GALL AMP XI.M18, "Bolting Integrity." The staff's evaluation is documented in SER Section 3.0.3.2.19. The program applies to bolting and torquing practices of safety-related and nonsafety-related carbon and stainless steel bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all safety and nonsafety-relates bolting regardless of size (except the reactor vessel closure studs which are address by the Reactor Vessel Closure Studs Program) and material. On this basis, the staff finds the loss of material from the exterior of copper-alloy tubing as well as from stainless steel bolting exposed to outdoor air is adequately managed using the System Walkdown Program and the Bolting Integrity Program. On this basis, the staff finds that management of loss of material in the condensate storage and transfer system is acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be 3-336adequately managed so that the intended function(s) will be maintained consistent with the CLBfor the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.20  RWCU Filter Demineralizer System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-8The staff reviewed LRA Table 3.3.2-13-8, which summarized the results of AMR evaluations forthe RWCU filter demineralizer system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-8 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.21  Circulating Water System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-9The staff reviewed LRA Table 3.3.2-13-9, which summarized the results of AMR evaluations forthe CW system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-9 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.22  Diesel Generator and Auxiliaries, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-10The staff reviewed LRA Table 3.3.2-13-10, which summarized the results of AMR evaluations forthe diesel generator and auxiliaries component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-10 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.23  Diesel Lube Oil System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation - LRA Table 3.3.2-13-11The staff reviewed LRA Table 3.3.2-13-11, which summarized the results of AMR evaluations forthe diesel lube oil system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-11 are consistent with the GALL Report.
3-337On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.24  Demineralized Water System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-12The staff reviewed LRA Table 3.3.2-13-12, which summarized the results of AMR evaluations forthe demineralized water system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-12 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.25  Feedwater System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-13In LRA Table 3.3.2-13-13, the applicant proposed to manage cracking-fatigue from carbon steelheat exchanger (shell), pump casing, and strainer housing exposed to steam and treated water greater than 220 F using the One-Time Inspection Program.The staff reviewed the applicant's One-Time Inspection Program and its evaluation isdocumented in SER Section 3.0.3.1.6.The One-Time Inspection Program provides assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's One-Time Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, "One-Time Inspection" and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." On this basis, the staff finds the cracking-fatigue from carbon steel heat exchanger (shell) exposed to steam and treated water greater than 220 F isadequately managed using the One-Time Inspection Program. On this basis, the staff finds that management of cracking-fatigue in the feedwater system is acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-3383.3.2.3.26  Fuel Oil System, Nonsafety-Related Components Affecting Safety-Related SystemsSummary of Aging Management Evaluation-LRA Table 3.3.2-13-14The staff reviewed LRA Table 3.3.2-13-14, which summarized the results of AMR evaluations forthe fuel oil system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-14 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.27  Fire Protection System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-15The staff reviewed LRA Table 3.3.2-13-15, which summarized the results of AMR evaluations forthe fire protection system component groups.In LRA Table 3.3.2-13-15, the applicant proposed to manage loss of material from copper-alloytubing and stainless steel bolting exposed to outdoor air using the System Walkdown Program.The staff reviewed the applicant's System Walkdown Program, which entails inspections ofexternal surfaces of components subject to an AMR. The staff's evaluation is documented in SER Section 3.0.3.1.9. The program is also credited with managing loss of material from internal surfaces, for situations in which internal and external material and environment combinations are the same such that external surface condition is representative of internal surface condition. The staff also reviewed the applicant's operating history and industry-wide operating experience. The System Walkdown Program includes visual inspections of copper-alloying tubing. The applicant also committed (Commitment #34) to a Bolting Integrity Program consistent with GALL AMP XI.M18, "Bolting Integrity." The staff's evaluation is documented in SER Section 3.0.3.2.19.
The program applies to bolting and torquing practices of safety-related and nonsafety-related carbon and stainless steel bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all safety and nonsafety-relates bolting regardless of size (except the reactor vessel closure studs which are address by the Reactor Vessel Closure Studs Program) and material. On this basis, the staff finds the loss of material from the exterior of copper-alloy tubing and stainless steel bolting exposed to outdoor air is adequately managed using the System Walkdown Program and the Bolting Integrity Program.
On this basis, the staff finds that management of loss of material in the fire protection system is acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-3393.3.2.3.28  Fuel Pool Cooling System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-16The staff reviewed LRA Table 3.3.2-13-16, which summarized the results of AMR evaluations forthe fuel pool cooling system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-16 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.29  Fuel Pool Cooling Filter Demineralizer System, Nonsafety-Related ComponentsAffecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-17The staff reviewed LRA Table 3.3.2-13-17, which summarized the results of AMR evaluations forthe fuel pool cooling filter demineralizer system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-17 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.30  House Heating Boiler System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-18The staff reviewed LRA Table 3.3.2-13-18, which summarized the results of AMR evaluations forthe house heating boiler system component groups.In LRA Table 3.3.2-13-18, the applicant proposed to manage loss of material from carbon steelheat exchangers (shell), piping, steam traps, strainer housings, and valve bodies exposed to steam or treated water using the Water Chemistry Control-Auxiliary Systems Program. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Auxiliary Systems Program.The staff reviewed the applicant's Water Chemistry Control Program for auxiliary systems, whichmanages aging effects for components exposed to treated water. The staff also reviewed the applicant's One-Time Inspection Program, which confirms the effectiveness of the Water Chemistry Control Program. The staff's evaluation of these program is documented in SER 3-340Sections 3.0.3.3.7 and 3.0.3.1.6, respectively. The Water Chemistry Control Program controlscontaminants at the lowest practical levels and provides corrosion protection for major systems and components. On this basis, the staff finds that loss of material from carbon steel piping, steam traps and valve bodies exposed to steam is adequately managed using the Water Chemistry Control Program-Auxiliary Systems Program augmented by the One-Time Inspection Program.In LRA Table 3.3.2-13-18, the applicant proposed to manage cracking-fatigue from carbon steelheat exchanger (shell) exposed to steam greater than 220 F using the One-Time InspectionProgram.The staff reviewed the applicant's One-Time Inspection Program and its evaluation isdocumented in SER Section 3.0.3.1.6.The One-Time Inspection Program provides assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's One-Time Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, "One-Time Inspection" and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." On this basis, the staff finds the cracking-fatigue from carbon steel heat exchanger (shell) exposed to steam greater than 220 F is adequately managed usingthe One-Time Inspection Program. On this basis, the staff finds that management of cracking-fatigue in the house heating boiler system is acceptable.On this basis, the staff finds that management of loss of material in the house heating boilersystem is acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.31  Hydraulic Control Units, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-19The staff reviewed LRA Table 3.3.2-13-19, which summarized the results of AMR evaluations forthe hydraulic control units component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-19 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-3413.3.2.3.32  High Pressure Coolant Injection System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-20The staff reviewed LRA Table 3.3.2-13-20, which summarized the results of AMR evaluations forthe HPCIS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-20 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.33  Heating, Ventilation, and Air Conditioning Systems, Nonsafety-Related ComponentsAffecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-21The staff reviewed LRA Table 3.3.2-13-21, which summarized the results of AMR evaluations forthe heating, ventilation and air conditioning systems component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-21 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.34  Instrument Air System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-22The staff reviewed LRA Table 3.3.2-13-22, which summarized the results of AMR evaluations forthe IA system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-22 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.35  MG Lube Oil System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-23The staff reviewed LRA Table 3.3.2-13-23, which summarized the results of AMR evaluations forthe MG lube oil system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-23 are consistent with the GALL Report.
3-342On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.36  Nitrogen System, Nonsafety-Related Components Affecting Safety-Related SystemsSummary of Aging Management Evaluation-LRA Table 3.3.2-13-24The staff reviewed LRA Table 3.3.2-13-24, which summarized the results of AMR evaluations forthe nitrogen system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-24 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.37  Nuclear Boiler System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-25The staff reviewed LRA Table 3.3.2-13-25, which summarized the results of AMR evaluations forthe nuclear boiler system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-25 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.38  Neutron Monitoring System, Nonsafety-related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-26The staff reviewed LRA Table 3.3.2-13-26, which summarized the results of AMR evaluations forthe neutron monitoring system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-26 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-3433.3.2.3.39  Post-Accident Sampling System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-27The staff reviewed LRA Table 3.3.2-13-27, which summarized the results of AMR evaluations forthe post-accident sampling system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-27 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.40  Primary Containment Atmosphere Control System, Nonsafety-Related ComponentsAffecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-28The staff reviewed LRA Table 3.3.2-13-28, which summarized the results of AMR evaluations forthe PCAC system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-28 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.41  Potable Water System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-29The staff reviewed LRA Table 3.3.2-13-29, which summarized the results of AMR evaluations forthe potable water system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-29 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.42  Reactor Building Closed Cooling Water System, Nonsafety-Related ComponentsAffecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-30The staff reviewed LRA Table 3.3.2-13-30, which summarized the results of AMR evaluations forthe reactor building CCWS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-30 are consistent with the GALL Report.
3-344On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.43  Reactor Core Isolation Cooling System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-31The staff reviewed LRA Table 3.3.2-13-31, which summarized the results of AMR evaluations forthe RCICS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-31 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.44  Radwaste, Liquid and Solid, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-32The staff reviewed LRA Table 3.3.2-13-32, which summarized the results of AMR evaluations forthe radwaste, liquid and solid component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-32 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.45  Residual Heat Removal System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-33The staff reviewed LRA Table 3.3.2-13-33, which summarized the results of AMR evaluations forthe RHRS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-33 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-3453.3.2.3.46  RHR Service Water System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-34The staff reviewed LRA Table 3.3.2-13-34, which summarized the results of AMR evaluations forthe RHRSW system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-34 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.47  Equipment Retired in Place, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-35The staff reviewed LRA Table 3.3.2-13-35, which summarized the results of AMR evaluations forthe equipment retired in place component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-35 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.48  Reactor Water Clean-Up System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-36The staff reviewed LRA Table 3.3.2-13-36, which summarized the results of AMR evaluations forthe reactor water clean-up system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-36 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.49  Standby Fuel Pool Cooling System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-37The staff reviewed LRA Table 3.3.2-13-37, which summarized the results of AMR evaluations forthe standby fuel pool cooling system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-37 are consistent with the GALL Report.
3-346On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.50  Standby Gas Treatment System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-38The staff reviewed LRA Table 3.3.2-13-38, which summarized the results of AMR evaluations forthe SGTS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-38 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.51  Stator Cooling System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-39The staff reviewed LRA Table 3.3.2-13-39, which summarized the results of AMR evaluations forthe stator cooling system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-39 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.52  Standby Liquid Control System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-40The staff reviewed LRA Table 3.3.2-13-40, which summarized the results of AMR evaluations forthe SLC system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-40 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-3473.3.2.3.53  Sampling System, Nonsafety-Related Components Affecting Safety-Related SystemsSummary of Aging Management Evaluation-LRA Table 3.3.2-13-41The staff reviewed LRA Table 3.3.2-13-41, which summarized the results of AMR evaluations forthe sampling system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-41 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.54  Service Water System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-42The staff reviewed LRA Table 3.3.2-13-42, which summarized the results of AMR evaluations forthe SWS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-42 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.55  HD & HV Instruments System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-43The staff reviewed LRA Table 3.3.2-13-43, which summarized the results of AMR evaluations forthe HD 7 HV Instruments System component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-43 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.56  Air Evacuation System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-44The staff reviewed LRA Table 3.3.2-13-44, which summarized the results of AMR evaluations forthe air evacuation system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-44 are consistent with the GALL Report.
3-348On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.57  Auxiliary System, Nonsafety-Related Components Affecting Safety-Related SystemsSummary of Aging Management Evaluation-LRA Table 3.3.2-13-45In LRA Table 3.3.2-13-45, the applicant proposed to manage cracking-fatigue from carbon steelheat exchanger (shell) exposed to treated water greater than 220 F using the One-TimeInspection Program.The staff reviewed the applicant's One-Time Inspection Program and its evaluation isdocumented in SER Section 3.0.3.1.6. The One-Time Inspection Program provides assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's One-Time Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, "One-Time Inspection" and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." On this basis, the staff finds the cracking-fatigue from carbon steel heat exchanger (shell) exposed to treated water greater than 220 F is adequatelymanaged using the One-Time Inspection Program. On this basis, the staff finds that management of cracking-fatigue in the auxiliary system is acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.58  Buildings (drainage system components) System, Nonsafety-Related ComponentsAffecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-46The staff reviewed LRA Table 3.3.2-13-46, which summarized the results of AMR evaluations forthe buildings system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-46 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-3493.3.2.3.59  Circulating Water Priming System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-47The staff reviewed LRA Table 3.3.2-13-47, which summarized the results of AMR evaluations forthe buildings system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-47 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.60  Extraction Steam System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-48In LRA Table 3.3.2-13-48, the applicant proposed to manage cracking due to fatigue forstainless steel expansion joints exposed to steam or treated water greater than 270F usingmetal fatigue TLAA.
 
The staff reviewed the applicant's metal fatigue TLAA for non-Class 1 components and its evaluation is documented in SER Section 4.3.2. The staff finds that the number of thermal cycles for non-Class 1 (ANSI B31.1 Code) piping and components is less than 7000 cycles for 60-years of operation. Therefore, the TLAA for non-Class 1 piping and components remains valid for the period of extended operation in compliance with 10 CFR 54.21(c)(i).On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.61  Heater Drain System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-49The staff reviewed LRA Table 3.3.2-13-49, which summarized the results of AMR evaluations forthe heater drain system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-49 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-3503.3.2.3.62  Heater Vents System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-50The staff reviewed LRA Table 3.3.2-13-50, which summarized the results of AMR evaluations forthe heater vents system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-50 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.63  Hydrogen Water Chemistry System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-51The staff reviewed LRA Table 3.3.2-13-51, which summarized the results of AMR evaluations forthe hydrogen water chemistry system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-51 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.64  Main Steam System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-52In LRA Table 3.3.2-13-52, the applicant proposed to manage cracking-fatigue from carbon steelheat exchanger (shell) exposed to steam greater than 270 F using the One-Time InspectionProgram.The staff reviewed the applicant's One-Time Inspection Program and its evaluation isdocumented in SER Section 3.0.3.1.6. The One-Time Inspection Program provides assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's One-Time Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, "One-Time Inspection" and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." On this basis, the staff finds the cracking-fatigue from carbon steel heat exchanger (shell) exposed to steam greater than 270 F is adequately managed usingthe One-Time Inspection Program. On this basis, the staff finds that management of cracking-fatigue in the main steam system is acceptable.
3-351On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.65  Make-up Demineralizer System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-53The staff reviewed LRA Table 3.3.2-13-53, which summarized the results of AMR evaluations forthe service air system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-53 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.66  Service Air System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-54The staff reviewed LRA Table 3.3.2-13-54, which summarized the results of AMR evaluations forthe service air system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-54 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.67  Seal Oil System, Nonsafety-Related Components Affecting Safety-Related SystemsSummary of Aging Management Evaluation-LRA Table 3.3.2-13-55The staff reviewed LRA Table 3.3.2-13-55, which summarized the results of AMR evaluations forthe seal oil system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-55 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-3523.3.2.3.68  Turbine Building Closed Cooling Water System, Nonsafety-Related ComponentsAffecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-56The staff reviewed LRA Table 3.3.2-13-56, which summarized the results of AMR evaluations forthe turbine building closed cooling water system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-56 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.69  Main Turbine Generator System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-57In LRA Table 3.3.2-13-57, the applicant proposed to manage cracking-fatigue from carbon steelpump and turbine casing exposed to steam and treated water greater than 270 F using theOne-Time Inspection Program.The staff reviewed the applicant's One-Time Inspection Program and its evaluation isdocumented in SER Section 3.0.3.1.6.The One-Time Inspection Program provides assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's One-Time Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, "One-Time Inspection" and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." On this basis, the staff finds the cracking-fatigue from carbon steel heat exchanger (shell) exposed to steam and treated water greater than 270 F isadequately managed using the One-Time Inspection Program. On this basis, the staff finds that management of cracking-fatigue in the main turbine generator system is acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.70  Turbine Lube Oil System, Nonsafety-Related Components Affecting Safety-RelatedSystems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-58The staff reviewed LRA Table 3.3.2-13-58, which summarized the results of AMR evaluations forthe turbine lube oil system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-58 are consistent with the GALL Report.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be 3-353adequately managed so that the intended function(s) will be maintained consistent with the CLBfor the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.3.71  Aging Effect/Mechanism in Table 3.3.1 That are Not Applicable for VYNPS The staff reviewed LRA Table 3.3.1, which provides a summary of aging managementevaluations for the auxiliary systems evaluated in the GALL Report.In LRA Table 3.3.1, Item 3.3.1-10 discussion column, the applicant stated that high strengthsteel bolting is not used in the auxiliary systems.The staff confirmed that there is no high strength steel bolting in the VYNPS auxiliary systems.
On the basis that there is no high strength steel bolting in the auxiliary systems at VYNPS, thestaff finds that this aging effect is not applicable at VYNPS.In LRA Table 3.3.1, Item 3.3.1-36, the applicant stated that the reduction of neutron-absorbingcapacity of Boraflex spent fuel storage racks neutron-absorbing sheets exposed to treated water due to Boraflex degradation is not applicable at VYNPS.The staff confirmed that Boraflex is not used at VYNPS. On the basis that there is no Boraflex inthe auxiliary systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS.In LRA Table 3.3.1, Item 3.3.1-39, the applicant stated that the cracking of stainless steel BWRspent fuel storage racks exposed to treated water greater than 60C (greater than140F) due toSCC is not applicable at VYNPS.The staff confirmed that the temperature of the water to which spent fuel racks are exposed islimited at VYNPS. On the basis that there are no stainless steel spent fuel storage racks exposed to treated water greater than140F, the staff finds that this aging effect is not applicableat VYNPS.In LRA Table 3.3.1, Item 3.3.1-41, the applicant stated that the cracking of high-strength steelclosure bolting exposed to air with steam or water leakage due to cyclic loading and SCC is not applicable at VYNPS.The staff confirmed that VYNPS auxiliary systems uses no high-strength steel closure bolting.On the basis that there is no high-strength steel bolting in the auxiliary systems at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS.In LRA Table 3.3.1, Item 3.3.1-42, the applicant stated that this line item was not used becausethe loss of material of steel closure bolting due to general corrosion was addressed by other line items.For loss of material due to general corrosion of steel closure bolting exposed to air with steam orwater leakage, the GALL Report recommends a program consistent with GALL AMP XI.M18, "Bolting Integrity."
3-354During the audit and review, the staff asked the applicant to clarify how aging of steel closurebolting would be managed in the absence of a Bolting Integrity Program. In a letter dated July 6, 2006, the applicant agreed to prepare and submit an AMP consistent with GALL AMP XI.M18, "Bolting Integrity," for approval. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staff's evaluation of this program is documented in SER Section 3.0.3.2.19. The staff finds that the applicant's Bolting Integrity Program conformed to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI. With this change, the applicant's management of steel closure bolting will be consistent with the GALL Report and therefore acceptable.In LRA Table 3.3.1, Item 3.3.1-44, the applicant stated that this line item was not used becausethe loss of material due to general, pitting, and crevice corrosion of steel compressed air system closure bolting exposed to condensation was addressed by other line items.For loss of material due to general, pitting, and crevice corrosion of steel compressed air systemclosure bolting exposed to condensation, the GALL Report recommends a program consistent with GALL AMP XI.M18, "Bolting Integrity."During the audit and review, the staff confirmed that all auxiliary system bolting within the scopeof license renewal is addressed using other LRA Table 3.3.1 items. During discussions with the applicant's technical personnel, the applicant staff stated that a Bolting Integrity Program is in development that will address the aging management of bolting within the scope of license renewal. In a letter dated July 6, 2006, the applicant committed to implement a Bolting Integrity Program which is consistent with GALL AMP XI.M18, "Bolting Integrity." In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staff's evaluation of this program is documented in SER Section 3.0.3.2.19. The staff finds that the applicant's Bolting Integrity Program conformed to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI. With this change, the applicant's management of bolting within the scope of license renewal will be consistent with the GALL Report and therefore acceptable.On the basis that loss of material from steel bolting will be managed in a manner consistent withthe recommendations of the GALL Report, the staff finds management of this aging effect to be acceptable even if LRA 3.3.1, Item 3.3.1-44 is not referenced.In LRA Table 3.3.1, Item 3.3.1-45, the applicant stated that loss of preload of steel closurebolting exposed to air due to thermal effects, gasket creep, and self-loosening is not applicable at VYNPS.During the audit and review, the staff confirmed that no auxiliary system closure bolting issubjected to temperature or pressure high enough to require aging management for this aging effect. On the basis that no VYNPS auxiliary system closure bolting is subjected to temperature or pressure high enough to require aging management, the staff finds that loss of preload is not applicable at VYNPS for this component type, environment, and aging effect.
3-355In LRA Table 3.3.1, Item 3.3.1-62, the applicant stated that loss of material due to pitting andcrevice corrosion of aluminum piping, piping components, and piping elements exposed to rawwater is not applicable at VYNPS because there are no aluminum components with intended functions exposed to raw water in the auxiliary systems.The staff confirmed that aluminum is not used for auxiliary systems SCs within the scope oflicense renewal at VYNPS. On the basis that aluminum is not used in the auxiliary systems SCs within the scope of license renewal at VYNPS, the staff finds that this aging effect is not
 
applicable.In LRA Table 3.3.1, Item 3.3.1-64, the applicant stated that this line item was not used becauseloss of material from steel components exposed to fuel oil was addressed by other line items.During the audit and review, the staff confirmed that loss of material from steel componentsexposed to fuel oil was addressed by other line items. The staff's review of those items is documented in SER Sections 3.3.2.2.9 and 3.3.2.2.12, respectively. On the basis that loss of material from steel components exposed to fuel oil is adequately managed, the staff finds that assignment of components in this category to other items in LRA Table 3.3.1 is acceptable.In LRA Table 3.3.1, Item 3.3.1-65, the applicant stated that this line item was not used becauseconcrete cracking and spalling due to aggressive chemical attack, and reaction with aggregates of reinforced concrete structural fire barriers are evaluated as structural components in LRA Section 3.5.On the basis that reinforced concrete structural fire barriers are evaluated in LRA Section 3.5,the staff finds that assignment of components in this category to other items in LRA Table 3.5.1 is acceptable.In LRA Table 3.3.1, Item 3.3.1-66, the applicant stated that this line item was not used becauseconcrete cracking and spalling due to freeze thaw, aggressive chemical attack, and reaction with aggregates of reinforced concrete structural fire barriers are evaluated as structural components in LRA Section 3.5.On the basis that reinforced concrete structural fire barriers are evaluated in LRA Section 3.5,the staff finds that assignment of components in this category to other items in LRA Table 3.5.1 is acceptable.In LRA Table 3.3.1, Item 3.3.1-67, the applicant stated that this line item was not used becauseloss of material due to corrosion of embedded steel of reinforced concrete structural fire barriers are evaluated as structural components in LRA Section 3.5.On the basis that reinforced concrete structural fire barriers are evaluated in LRA Section 3.5,the staff finds that assignment of components in this category to other items in LRA Table 3.5.1 is acceptable.
3-356In LRA Table 3.3.1, Item 3.3.1-74, the applicant stated that this line item was not used becauseloss of material due to wear of steel crane rails is evaluated in accordance with structural components in LRA Section 3.5.During the audit and review, the staff noted that steel crane structural girders are evaluated asstructural components in LRA Section 3.5, however, loss of material due to wear is not explicitly addressed. The applicant's technical personnel stated that reactor building steel crane structural girders used in load handling are inspected in accordance with the Periodic Surveillance and Preventive Maintenance Program identified in (LRA Appendix B). Process facility crane rails and girders are inspected in accordance with the Structures Monitoring Program as identified in (LRA Appendix B). The Structures Monitoring Program will be enhanced, as identified in Appendix B, to address crane rails and girders. Aging management activities for crane rails and girders in accordance with these two programs are consistent with the program elements described for the GALL AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling)
Handling Systems." The staff finds this consistent with the GALL Report and is therefore acceptable.On the basis that loss of material due to wear of crane rails will be managed in a mannerconsistent with the recommendations of the GALL Report, the staff finds management of this aging effect acceptable. In LRA Table 3.3.1, Item 3.3.1-75, the applicant stated that the hardening and loss of strengthdue to elastomer degradation and loss of material due to erosion of elastomer seals and components exposed to raw water is not applicable at VYNPS.The staff confirmed that there are no elastomeric components exposed to raw or untreatedwater in the auxiliary systems that require aging management. On the basis that there are no elastomeric components in the auxiliary systems at VYNPS that require aging management, the staff finds that, for this component type, this aging effect is not applicable to VYNPS.In LRA Table 3.3.1, Item 3.3.1-78, the applicant stated that loss of material due to pitting andcrevice corrosion of stainless steel and copper alloy piping, piping components, and pipingelements exposed to raw water are managed in accordance with other items from LRA Table 3.3.1 or in the case of nickel-alloy components, need not be managed because there is no such material within the scope of license renewal for VYNPS auxiliary systems.During the audit and review, the staff confirmed that nickel alloy is not used for auxiliary SSCswithin the scope of license renewal at VYNPS. The staff also confirmed that loss of material due to pitting and crevice corrosion of stainless steel and copper alloy piping, piping components,and piping elements exposed to raw water is managed in accordance with other items from LRA Table 3.3.1. The staff's review of those items is documented in SER Section 3.3.2.1. On the basis that pitting and crevice corrosion of stainless steel and copper alloy piping, pipingcomponents, and piping elements exposed to raw water is adequately managed, the staff finds that assignment of components in this category to other items in LRA Table 3.3.1 is acceptable.
3-357In LRA Table 3.3.1, Item 3.3.1-80, the applicant stated that the loss of material of stainless steeland copper alloy piping, piping components, and piping elements exposed to raw water due to pitting, crevice, and MIC is not applicable at VYNPS.The staff confirmed that at VYNPS, EDG system piping, piping components, and pipingelements are not exposed to raw water. On the basis that there are no EDG piping components subject to aging management at VYNPS exposed to raw water, the staff finds that, for this component type, this aging effect is not applicable to VYNPS. (Heat exchanger components exposed to raw water are addressed in accordance with other items of LRA Table 3.3.1-1.)In LRA Table 3.3.1, Item 3.3.1-86, the applicant stated that this line item was not used becauseloss of material due to general, pitting, and crevice corrosion of new fuel storage rack assemblies is evaluated with structural components in LRA Section 3.5.On the basis that reinforced concrete structural steel are evaluated in LRA Section 3.5, the stafffinds that assignment of components in this category to other items in LRA Table 3.5.1 is acceptable.In LRA Table 3.3.1, Item 3.3.1-92, the applicant stated that galvanized steel surfaces areevaluated as steel for the auxiliary systems at VYNPS. On the basis that galvanized steel surfaces are evaluated as steel for the auxiliary systems, thestaff finds the managed of galvanized steel acceptable.In LRA Table 3.3.1, Item 3.3.1-95, the applicant stated that there are no auxiliary systemcomponents exposed to controlled indoor air at VYNPS.On the basis that there is no auxiliary system components exposed to controlled indoor air in theauxiliary systems at VYNPS, the staff finds that this aging effect is not applicable at VYNPS.In LRA Table 3.3.1, Item 3.3.1-98, the applicant stated that dried (treated) air is maintained asan environment as a result of the Instrument Air Quality Program, so aging effects may occur without that program. Because this program is in place, this environment is maintained at VYNPS. On this basis, steel,stainless steel, and copper alloy piping, piping components, and piping elements exposed todried air does not need to be managed at VYNPS.3.3.2.3.72  Auxiliary Systems AMR Line Items That Have No Aging Effects (LRA Tables 3.3.2-1through 3.3.2-13-58)In LRA Tables 3.3.2-1 through 3.3.2-13-58, the applicant identified line items where no agingeffects were identified as a result of its aging review process.In LRA Tables 3.3.2-1 through 3.3.2-13-58, the applicant identified no aging effects forcomponent types of various materials exposed to indoor air. This includes a flame arrestor in the fuel oil system fabricated from aluminum; tubing in the fire protection water system made of copper alloy; and nozzles, piping, tubing, siren or valve bodies in the fire protection system made 3-358of copper alloy. Similarly, the applicant finds no aging effects for stainless steel nozzles, tubing,and valve bodies of the fire protection system; valve bodies of the SWS; as well as diaphragms, dryers, filter housings, heat exchangers, orifices, piping, pump casings, traps, tubing, and valve bodies of the primary containment atmospheric control and containment air dilution system exposed to indoor air.The GALL Report identified that aluminum in an indoor uncontrolled air environment exhibits noaging effect and that the component or structure will therefore remain capable of performing its intended functions consistent with the CLB for the period of extended operation. Aluminum has an excellent resistance to corrosion when exposed to humid air (an uncontrolled indoor environment). The aluminum oxide film is bonded strongly to its surface and that film, if damaged, reforms immediately in most environments. On a surface freshly abraded and then exposed to air, the oxide film is only 5 to 10 nanometers thick but is highly effective in protecting the aluminum from further corrosion. For this reason, the staff finds that aluminum exposed to indoor uncontrolled air environment does not require aging management.The GALL Report identified that copper alloy in an indoor, uncontrolled air environment exhibitsno aging effect and that the component or structure will therefore remain capable of performing its intended functions consistent with the CLB for the period of extended operation. This conclusion is based on the fact that comprehensive tests conducted over a 20-year period in accordance with the supervision of ASTM have confirmed the suitability of copper and copper alloys for atmospheric exposure. For this reason, the staff finds that copper alloy exposed to indoor uncontrolled air environment does not require aging management.Finally, the GALL Report identified that stainless steel in an indoor, uncontrolled air environmentexhibits no aging effect and that the component or structure will therefore remain capable of performing its intended functions consistent with the CLB for the period of extended operation.
This conclusion is based on the fact that stainless steels are highly resistant to corrosion in dryatmospheres in the absence of corrosive species, (which would be reflective of indoor uncontrolled air). Components are not subject to moisture in a dry air environment (and indoor uncontrolled air would have limited humidity and condensation). For this reason, the staff finds that stainless steel exposed to indoor uncontrolled air environment does not require aging management.The staff finds that no aging effects are considered to be applicable to components fabricatedfrom aluminum, copper alloy, or stainless steel exposed to air.The applicant identified no aging effects for a PACCAD system stainless steel diaphragmsexposed to silicone.The GALL Report identified that stainless steels are highly resistant to corrosion in dryatmospheres in the absence of corrosive species.On this basis, and considering that silicone does not react with stainless steel, the staff finds thatthere are no AERM for stainless steel diaphragms of the PACCAD system exposed to silicone.
3-359The applicant also identified no aging effects for stainless steel bolting in the CW systemexposed to outdoor air. During the audit and review, the staff asked the applicant to provide the location of the CW system bolting components at VYNPS and clarify how they are protected from constant wetting and drying conditions. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state for stainless steel bolting exposed to outdoor air, the loss of material is to be managed by the System Walkdown Program.The staff reviewed the System Walkdown Program, which entails inspections of externalsurfaces of components subject to an AMR. The staff's evaluation is documented in SER Section 3.0.3.1.9. The program is also credited with managing loss of material from internal surfaces, for situations in which internal and external material and environment combinations are the same such that external surface condition is representative of internal surface condition. On this basis, the staff finds the loss of stainless steel from bolting exposed to air is adequately managed using the System Walkdown Program.The applicant also identified no aging effects for an HVAC system sight glass exposed tocondensation.The GALL Report identified that glass in a raw water environment exhibits no aging effect andthe component or structure will therefore remain capable of performing its intended functions consistent with the CLB for the period of extended operation. This conclusion is based on the fact that silicate glasses are highly inert and operating experience has demonstrated that there are no aging related failures of glass in this environment. For this reason, the staff finds that glass exposed to condensation does not require aging management.The staff finds that no aging effects are considered to be applicable to an HVAC system sightglass exposed to condensation.The applicant also identified no aging effects for an SLC system sight glass exposed to sodiumpentaborate solution.The GALL Report identified that glass in a borated water environment exhibits no aging effectand the component or structure will therefore remain capable of performing its intended functions consistent with the CLB for the period of extended operation. This conclusion is based on the fact that silicate glasses are highly inert and operating experience has demonstrated that there are no aging related failures of glass in this environment. For this reason, the staff finds that glass exposed to condensation does not require aging management.The staff finds that no aging effects are considered to be applicable to an SLC system sightglass exposed to sodium pentaborate solution.The applicant also identified no aging effects for fiberglass piping and tanks exposed to fuel oil.
The GALL Report identified that glass in a fuel oil environment exhibits no aging effect, andfound that components of glass exposed to fuel oil will remain capable of performing their intended functions consistent with the CLB for the period of extended operation.
3-360On the basis that fiberglass (comprising glass and polymers) is similarly resistant to chemicalattack by fuel oil, the staff finds that fiberglass piping and tanks exposed to fuel oil will exhibit no aging effect requiring aging management.The applicant also identified no aging effects for fiberglass piping and tanks exposed to soil.
The GALL Report identified that glass in a raw water environment exhibits no aging effect, andfound that components of glass exposed to raw water will remain capable of performing their intended functions consistent with the CLB for the period of extended operation.On the basis that a soil environment is no more aggressive than raw water and that fiberglass(comprising glass and polymers) is similarly resistant to chemical attack, the staff finds that fiberglass piping and tanks buried in soil will exhibit no aging effect requiring aging management.The applicant also identified no aging effects for fiberglass tanks exposed to interstitial fluid(brine).During the audit and review, the applicant was asked to clarify the nature of the interstitial fluid.The applicant's technical personnel explained that the interstitial fluid (brine) environment is colored water, treated with antifreeze and located between the inner and outer walls of a double-walled fiberglass fuel oil tank. The fluid is used for leak detection and is provided by the manufacturer of the tank.The GALL Report identifies no aging effect for glass in a treated water environment. The agingeffects/mechanisms identified for other non-metallics are not relevant to the function of the fiberglass fuel tank.On this basis, the staff finds no aging effect requiring aging management for fiberglass exposedto interstitial fluid.The applicant also identified no aging effects for fiberglass flexible duct connections exposed toindoor air.For other non-metallic components, the applicant considered degradation from sustainedvibratory loading and from wear. During the audit and review, the staff asked the applicant's technical personnel to clarify the basis for concluding that these aging mechanisms are not applicable to flexible duct connections of fiberglass. The applicant stated that wear is the loss of surface layers due to relative motion between two surfaces and that at in the auxiliary systems VYNPS, this specific aging effect is not applicable because the heating, ventilation, and airconditioning elastomer coated fiberglass duct flexible connections are fixed at both ends, precluding wear. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant revised LRA Section 3.3.2.2.13 to state: Wear is the removal of surface layers due to relative motion between twosurfaces. At VYNPS, in the auxiliary systems, this specific aging effect is not applicable because the heating, ventilation, and air conditioning elastomer coated fiberglass duct flexible connections are fixed at both ends, precluding wear. This item is not applicable to VYNPS auxiliary systems.
3-361On the basis of its review, the staff finds that wear is precluded by the system design featureand that this aging effect/mechanism is not applicable to VYNPS auxiliary systems. On this basis, the staff finds no AERM for fiberglass duct flexible connections exposed to indoor air.
Conclusion. On the basis of its review, the staff finds that the applicant appropriately evaluatedthe AMR results involving material, environment, AERM, and AMP combinations that are not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.3  ConclusionThe staff concludes that the applicant has provided sufficient information to demonstrate that theeffects of aging for the auxiliary systems components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.4  Aging Management of Steam and Power Conversion SystemsThis section of the SER documents the staff's review of the applicant's AMR results for thesteam and power conversion systems components and component groups of:
* auxiliary steam
* condensate
* main steam
* 101 (main steam, extraction steam, and auxiliary steam instruments)3.4.1  Summary of Technical Information in the ApplicationLRA Section 3.4 provides AMR results for the steam and power conversion systemscomponents and component groups. LRA Table 3.4.1, "Summary of Aging Management Evaluations for the Steam and Power Conversion System," is a summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the steam and power conversion systems components and component groups.The applicant's AMRs evaluated and incorporated applicable plant-specific and industryoperating experience in the determination of AERMs. The plant-specific evaluation included condition reports and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.3.4.2  Staff EvaluationThe staff reviewed LRA Section 3.4 to determine whether the applicant provided sufficientinformation to demonstrate that the effects of aging for the steam and power conversion systems components within the scope of license renewal and subject to an AMR will be 3-362adequately managed so that the intended function(s) will be maintained consistent with the CLBfor the period of extended operation, as required by 10 CFR 54.21(a)(3).The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRswere consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's audit evaluation are documented in SER Section 3.4.2.1.In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for whichfurther evaluation is recommended. The staff confirmed that the applicant's further evaluations were consistent with the SRP-LR Section 3.4.2.2 acceptance criteria. The staff's audit evaluations are documented in SER Section 3.4.2.2.The staff also conducted a technical review of the remaining AMRs that were not consistent with,or not addressed in, the GALL Report. The technical review evaluated whether all plausible aging effects have been identified and whether the aging effects listed were appropriate for the material-environment combinations specified. The staff's evaluations are documented in SER Section 3.4.2.3.Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensurethat they provided an adequate description of the programs credited with managing or monitoring aging for the steam and power conversion systems components.For SSCs which the applicant claimed were not applicable or required no aging management,the staff reviewed the AMR line items and the plant's operating experience to verify the applicant's claims.Table 3.4-1 summarizes the staff's evaluation of components, aging effects/mechanisms, andAMPs listed in LRA Section 3.4 and addressed in the GALL Report.Table 3.4-1  Staff Evaluation for Steam and Power Conversion Systems Components inthe GALL Report ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation Steel piping, piping components, and piping
 
elements exposed to
 
steam or treated water
 
(3.4.1-1)Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAAFatigue is a TLAA (See SER Section 3.4.2.2.1)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-363 Steel piping, piping components, and piping
 
elements exposed to
 
steam (3.4.1-2)Loss of material due to general, pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.4.2.2.2)
Steel heatexchanger components exposed to treated water
 
(3.4.1-3)Loss of material due to general, pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionNoneNot applicable toBWRs Steel piping, piping components, and piping
 
elements exposed to treated water
 
(3.4.1-4)Loss of material due to general, pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.4.2.2.2)
Steel heatexchanger components exposed to treated water
 
(3.4.1-5)Loss of material due to general, pitting, crevice, and galvanic corrosionWater Chemistryand One-Time
 
InspectionNoneNot applicable (See SER Section 3.4.2.2.9)
Steel and stainless steel tanks exposed
 
to treated water (3.4.1-6)Loss of material due to general (steel only) pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionNoneNot applicable (See SER Section 3.4.2.2.2)
Steel piping, piping components, and piping
 
elements exposed to
 
lubricating oil
 
(3.4.1-7)Loss of material due to general, pitting and crevice corrosionLubricating OilAnalysis and One-Time InspectionNoneNot applicable (See SER Section 3.4.2.2.2)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-364 Steel piping, piping components, and piping
 
elements exposed to raw water (3.4.1-8)Loss of material due to general, pitting, crevice, and MIC, and foulingPlant-specificNoneNot applicable (See SER Section 3.4.2.2.3)
Stainless steel and copper alloy heat exchanger tubes exposed
 
to treated water (3.4.1-9)Reduction of heat transfer due to
 
foulingWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.4.2.2.4)
Steel, stainless steel, and copper alloy heat exchanger tubes exposed
 
to lubricating
 
oil (3.4.1-10)Reduction of heat transfer due to
 
foulingLubricating OilAnalysis and One-Time InspectionNoneNot applicable (See SER Section 3.4.2.2.4)
Buried steel piping, piping
 
components, piping elements, and tanks (with or without coating or wrapping) exposed to
 
soil (3.4.1-11)
Loss of material due to general, pitting, crevice, and MIC Buried Piping andTanks Surveillance or Buried Piping andTanks InspectionNoneNot applicable (See SER Section 3.4.2.2.5)
Steel heatexchanger components exposed to
 
lubricating oil
 
(3.4.1-12)
Loss of material due to general, pitting, crevice, and MICLubricating OilAnalysis and One-Time InspectionNoneNot applicable (See SER Section 3.4.2.2.5)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-365 Stainless steel piping, piping
 
components, piping elements exposed to
 
steam (3.4.1-13)Cracking due to SCCWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.4.2.2.6)
Stainless steel piping, piping
 
components, piping elements, tanks, and
 
heat exchanger components exposed to treated water
 
> 60C (> 140F)(3.4.1-14)Cracking due to SCCWater Chemistryand One-Time
 
InspectionNoneNot applicable.(There are no
 
stainless steel
 
components exposed to treated water with intended
 
functions in the steam and power conversion systems.)
(See SER Section 3.4.2.2.6)
Aluminum and copper alloy
 
piping, piping
 
components, and piping
 
elements exposed to treated water
 
(3.4.1-15)
Loss of material due to pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionWater ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection Program (B.1.21)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.4.2.2.7)
Stainless steel piping, piping
 
components, and piping
 
elements; tanks, and
 
heat exchanger components exposed to treated water
 
(3.4.1-16)
Loss of material due to pitting and crevice corrosionWater Chemistryand One-Time
 
InspectionNoneNot applicable.(There are no
 
stainless steel
 
components exposed to treated water with intended
 
functions in the steam and power conversion systems.)
(See SER Section 3.4.2.2.7)
Stainless steel piping, piping
 
components, and piping
 
elements exposed to
 
soil (3.4.1-17)
Loss of material due to pitting and crevice corrosionPlant-specificNoneNot applicable (See SER Section 3.4.2.2.7)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-366Copper alloy piping, piping
 
components, and piping
 
elements exposed to
 
lubricating oil
 
(3.4.1-18)
Loss of material due to pitting and crevice corrosionLubricating OilAnalysis and One-Time InspectionNoneNot applicable (See SER Section 3.4.2.2.7)
Stainless steel piping, piping
 
components, piping elements, and
 
heat exchanger components exposed to
 
lubricating oil
 
(3.4.1-19)
Loss of material dueto pitting, crevice, and MICLubricating OilAnalysis and One-Time InspectionNoneNot applicable (See SER Section 3.4.2.2.8)
Steel tanksexposed to air
- outdoor (external)
 
(3.4.1-20)
Loss of material/
general, pitting, and crevice corrosionAboveground SteelTanksNoneNot applicable.(There are no steel tanks exposed to outdoor air with
 
intended functions
 
in the steam and power conversion systems.)
(See SER Section 3.4.2.3.2)High-strength steel closure
 
bolting exposed to air with steam or water leakage
 
(3.4.1-21)Cracking due tocyclic loading, SCCBolting IntegrityNoneNot applicable.(High-strength steel
 
closure bolting is
 
not used in the steam and power conversion systems.) (See SER
 
Section 3.4.2.3.2)
Steel bolting and closure
 
bolting exposed to air with steam or water leakage, air-outdoor (external), or
 
air-indoor
 
uncontrolled (external);
 
(3.4.1-22)
Loss of material due to general, pitting and crevice corrosion; loss of
 
preload due to
 
thermal effects, gasket creep, and
 
self-looseningBolting IntegrityBolting Integrity ProgramConsistent withGALL Report. (See
 
SER Section 3.4.2.1.6)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-367 Stainless steel piping, piping
 
components, and piping
 
elements exposed to closed-cycle cooling water
 
> 60C (> 140F)(3.4.1-23)Cracking due to SCCClosed-CycleCooling Water SystemNoneNot applicable.(There are no
 
stainless steel
 
components exposed to closed-cycle cooling water in the steam and power conversion systems.)Steel heatexchanger components exposed to closed-cycle cooling water
 
(3.4.1-24)
Loss of material due to general, pitting, crevice, and galvanic corrosionClosed-CycleCooling Water SystemNoneNot applicable.(There are no steel heat exchanger
 
components exposed to closed-cycle cooling water in the steam and power conversion systems.)
(See SER Section 3.4.2.3.2)
Stainless steel piping, piping
 
components, piping elements, and
 
heat exchanger components exposed to closed-cycle cooling water
 
(3.4.1-25)
Loss of material due to pitting and crevice corrosionClosed-CycleCooling Water SystemWater ChemistryControl-Closed Cooling Water
 
Program (B.1.30.3)Consistent withGALL Report. (See
 
SER Section 3.4.2.1)Copper alloy piping, piping
 
components, and piping
 
elements exposed to closed-cycle cooling water
 
(3.4.1-26)
Loss of material dueto pitting, crevice, and galvanic corrosionClosed-CycleCooling Water SystemNoneNot applicable.(There are no
 
copper alloy
 
components exposed to closed-cycle cooling water in the steam and power conversion systems.)
(See SER Section 3.4.2.3.2)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-368 Steel, stainless steel, and copper alloy heat exchanger tubes exposed to closed-cycle cooling water
 
(3.4.1-27)Reduction of heat transfer due to
 
foulingClosed-CycleCooling Water SystemNoneNot applicable.(There are no heat exchanger tubes exposed to closed-cycle cooling water in the steam and power conversion systems.)Steel external surfaces exposed to
 
air-indoor
 
uncontrolled (external),
condensation (external), or
 
air-outdoor (external)
 
(3.4.1-28)
Loss of material due to general corrosionExternal SurfacesMonitoringSystem Walkdown Program (B.1.28)Consistent withGALL Report (See
 
SER Section 3.4.2.1.7)
Steel piping, piping components, and piping
 
elements exposed to
 
steam or treated water
 
(3.4.1-29)Wall thinning due toflow-accelerated corrosionFlow-AcceleratedCorrosionFlow-AcceleratedCorrosion Program (B.1.13)Consistent withGALL Report (See
 
SER Section 3.4.2.1.8)
Steel piping, piping components, and piping
 
elements exposed to
 
air-outdoor (internal) or
 
condensation (internal)
 
(3.4.1-30)
Loss of material due to general, pitting, and crevice corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting ComponentsSystem Walkdown Program (B.1.28)Consistent withGALL Report (See
 
SER Section 3.4.2.1.9)
Steel heatexchanger components exposed to raw water (3.4.1-31)
Loss of material due to general, pitting, crevice, galvanic, and MIC, and
 
foulingOpen-Cycle CoolingWater System PeriodicSurveillance and Preventive Maintenance
 
Program (B.1.22)Consistent withGALL Report (See
 
SER Section 3.4.2.1.10)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-369 Stainless steel and copper alloy piping, piping components, and piping
 
elements exposed to raw water (3.4.1-32)
Loss of material dueto pitting, crevice, and MICOpen-Cycle CoolingWater System PeriodicSurveillance and Preventive Maintenance
 
Program (B.1.22)Consistent withGALL Report, (See
 
SER Section 3.4.2.1.11)
Stainless steel heat exchanger components exposed to raw water (3.4.1-33)
Loss of material dueto pitting, crevice, and MIC, and
 
foulingOpen-Cycle CoolingWater SystemNoneNot applicable.(There are no
 
stainless steel heat exchanger components exposed to raw water in the steam and power conversion systems.)
(See SER Section 3.4.2.3.2)
Steel, stainless steel, and copper alloy heat exchanger tubes exposed to raw water
 
(3.4.1-34)Reduction of heat transfer due to
 
foulingOpen-Cycle CoolingWater SystemNoneNot applicable.There are no heat exchanger tubes exposed to raw water with an
 
intended function of
 
heat transfer in the steam and power conversion systems.)
(See SER Section 3.4.2.3.2)Copper alloy
> 15 percent Zn
 
piping, piping
 
components, and piping
 
elements exposed to closed-cycle cooling water, raw water, or treated water
 
(3.4.1-35)
Loss of material dueto selective leachingSelective Leachingof MaterialsNoneNot applicable.(There are no
 
copper alloy
 
components subject to selective leaching
 
in the steam and power conversion systems.)
(See SER Section 3.4.2.3.2)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-370Gray cast iron piping, piping
 
components, and piping
 
elements exposed to
 
soil, treated water, or raw water (3.4.1-36)
Loss of material dueto selective leachingSelective Leachingof MaterialsNoneNot applicable.(There are no gray cast iron components exposed to raw water with intended
 
functions in the steam and power conversion systems.)
(See SER Section 3.4.2.3.2)
Steel, stainless steel, and nickel-based alloy piping, piping components, and piping
 
elements exposed to
 
steam (3.4.1-37)
Loss of material due to pitting and crevice corrosionWater ChemistryWater ChemistryControl-BWR
 
Program (B.1.30.2);
Water Chemistry Control-Auxiliary Systems Program (B.1.30.1)Consistent withGALL Report (See
 
SER Section 3.4.2.1.12)
Steel boltingand external
 
surfaces exposed to air with borated water leakage
 
(3.4.1-38)
Loss of material due to boric acid corrosionBoric AcidCorrosionNoneNot applicable toBWRs Stainless steel piping, piping
 
components, and piping
 
elements exposed to
 
steam (3.4.1-39)Cracking due to SCCWater ChemistryNoneNot applicable toBWRsGlass piping elements exposed to air, lubricating oil, raw water, and treated water
 
(3.4.1-40)NoneNoneNoneNot applicable.(There are no glass components with
 
intended functions
 
in the steam and power conversion systems.)
ComponentGroup(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-371 Stainless steel, copper alloy, and
 
nickel alloy
 
piping, piping
 
components, and piping
 
elements exposed to
 
air-indoor
 
uncontrolled (external)
 
(3.4.1-41)NoneNoneNoneConsistent withGALL Report. (See
 
SER Section 3.4.2.1)
Steel piping, piping components, and piping
 
elements exposed to
 
air-indoor
 
controlled (external)
 
(3.4.1-42)NoneNoneNoneNot applicable.(There are no steel
 
components exposed to
 
air-indoor controlled
 
in the steam and power conversion systems.)Steel and stainless steel
 
piping, piping
 
components, and piping
 
elements in
 
concrete (3.4.1-43)NoneNoneNoneNot applicable.(There are no steel
 
or stainless steel
 
components exposed to concrete
 
in the steam and power conversion systems.)Steel, stainless steel, aluminum, and
 
copper alloy
 
piping, piping
 
components, and piping
 
elements exposed to
 
gas (3.4.1-44)NoneNoneNoneNot applicable.(There are no steel, stainless steel, aluminum, or
 
copper alloy
 
components exposed to gas in
 
the steam and power conversion systems.)The staff's review of the steam and power conversion systems component groups followed anyone of several approaches. One approach, documented in SER Section 3.4.2.1, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.4.2.2, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.4.2.3, reviewed AMR results for components that the applicant indicated are not 3-372consistent with or not addressed in the GALL Report. The staff's review of AMPs credited tomanage or monitor aging effects of the steam and power conversion systems components is documented in SER Section 3.0.3.3.4.2.1  AMR Results Consistent with the GALL ReportSummary of Technical Information in the Application. LRA Section 3.4.2.1 identifies thematerials, environments, AERMs, and the following programs that manage aging effects for the steam and power conversion systems components:
* Flow-Accelerated Corrosion Program
* System Walkdown Program
* Water Chemistry Control - BWR Program
* Water Chemistry Control - Closed Cooling Water ProgramLRA Table 3.4.2-1 summarizes AMRs for the steam and power conversion systems componentsand indicates AMRs claimed to be consistent with the GALL Report.Staff Evaluation. For component groups evaluated in the GALL Report for which the applicantclaimed consistency with the report and for which it does not recommend further evaluation, the staff's audit and review determined whether the plant-specific components of these GALL Report component groups were bounded by the GALL Report evaluation.The applicant noted for each AMR line item how the information in the tables aligns with theinformation in the GALL Report. The staff audited those AMRs with notes A through E indicating how the AMR is consistent with the GALL Report.Note A indicates that the AMR line item is consistent with the GALL Report for component,material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP.
The staff audited these line items to verify consistency with the GALL Report and validity of the AMR for the site-specific conditions.Note B indicates that the AMR line item is consistent with the GALL Report for component,material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify consistency with the GALL Report and verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also finds whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions.Note C indicates that the component for the AMR line item, although different from, is consistentwith the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified in the GALL Report a different component with the same material, environment, aging effect, and AMP as the component under review. The staff audited these line items to verify consistency with the GALL Report. The staff also finds whether the AMR line item of the different component was applicable to the component under review and whether the AMR was valid for the site-specific conditions.
3-373Note D indicates that the component for the AMR line item, although different from, is consistentwith the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component was applicable to the component under review and whether the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also finds whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions.Note E indicates that the AMR line item is consistent with the GALL Report for material,environment, and aging effect, but credits a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also finds whether the credited AMP would manage the aging effect consistently with the GALL AMP and whether the AMR was valid for the site-specific conditions.The staff audited and reviewed the information in the LRA. The staff did not repeat its review ofthe matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluation follows.3.4.2.1.1  Loss of Material Due to General, Pitting, and Crevice Corrosion In LRA Table 3.4.1, Item 3.4.1-2, the applicant stated that the Water Chemistry Control-BWRProgram, augmented by the One-Time Inspection Program, to verify program effectiveness, will be used to manage loss of material for steel components exposed to steam in the ESF systems listed in LRA Table 3.2.2 and components in-scope in accordance with 10 CFR 54.4(a)(2) criterion and listed in LRA Tables 3.3.2-13-xx series.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly credited in the system table (Table 3.4.2-1), only the Water Chemistry Control-BWR Program was credited. In a letter dated July 14, 2006, the applicant amended the LRA. The applicant revised its Water Chemistry Control-BWR Program to include the sentence:
"The One-Time Inspection Program will confirm the effectiveness of the program." The staff reviewed the applicant's Water Chemistry Control-BWR Program and the One-TimeInspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff finds that the applicant's Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130).
The staff also finds that the applicant's One-Time Inspection Program is used to verify the effectiveness of the Water Chemistry Control-BWR Program consistent with the GALL Report and therefore acceptable.3.4.2.1.2  Loss of Material Due to General, Pitting, and Crevice Corrosion In LRA Table 3.4.1, Item 3.4.1-4, the applicant stated that the Water Chemistry Control-BWRProgram, augmented by the One-Time Inspection Program, to verify program effectiveness, will be used to manage loss of material for steel piping, piping components, and piping elementsexposed to treated water and also in the components that are in-scope in accordance with 10 CFR 54.4(a)(2) criterion and listed in LRA Tables 3.3.2-13-xx series.
3-374During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly credited in the system table (Table 3.4.2-1), only the Water Chemistry Control-BWR Program was credited. In a letter dated July 14, 2006, the applicant amended the LRA. The applicant revised its Water Chemistry Control-BWR Program to include the sentence:
"The One-Time Inspection Program will confirm the effectiveness of the program."The staff reviewed the applicant's Water Chemistry Control-BWR Program and the One-TimeInspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff finds that the applicant's Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130).
The staff also finds that the applicant's One-Time Inspection Program is used to verify the effectiveness of the Water Chemistry Control-BWR Program consistent with the GALL Report and therefore acceptable. 3.4.2.1.3  Reduction of Heat Transfer Due to Fouling In LRA Table 3.4.1, Item 3.4.1-9, the applicant stated that the Water Chemistry Control-BWRProgram, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage the reduction of heat transfer in copper alloy heat exchanger tubes exposed to treated water in the steam and power conversion systems. These programs will also be used to manage reduction of heat transfer in the HPCI and RCIC systems as listed in LRA Tables 3.2.2-4 and 3.2.2-5.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly credited in the system table (Table 3.4.2-1), only the Water Chemistry Control-BWR Program was credited. In a letter dated July 14, 2006, the applicant amended the LRA. The applicant revised its Water Chemistry Control-BWR Program to include the sentence:
"The One-Time Inspection Program will confirm the effectiveness of the program."The staff reviewed the applicant's Water Chemistry Control-BWR Program and the One-TimeInspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff finds that the applicant's Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130).
The staff also finds that the applicant's One-Time Inspection Program is used to verify the effectiveness of the Water Chemistry Control-BWR Program consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.4.2.1.4  Cracking Due to Stress Corrosion Cracking In LRA Table 3.4.1, Item 3.4.1-13, the applicant stated that the Water Chemistry Control-BWRProgram, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage cracking due to SCC for stainless steel components exposed to steam.
3-375During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly credited in the system table (Table 3.4.2-1), only the Water Chemistry Control-BWR Program was credited. In a letter dated July 14, 2006, the applicant amended the LRA. The applicant revised its Water Chemistry Control-BWR Program to include the sentence:
"The One-Time Inspection Program will confirm the effectiveness of the program."The staff reviewed the applicant's Water Chemistry Control - BWR Program and the One-TimeInspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff finds that the applicant's Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130).
The staff also finds that the applicant's One-Time Inspection Program is used to verify the effectiveness of the Water Chemistry Control-BWR Program consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.4.2.1.5  Loss of Material Due to Pitting and Crevice Corrosion In Table 3.4.1, Item 3.4.1-15, the applicant stated that the Water Chemistry Control-BWRProgram, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material of aluminum and copper alloy components exposed to treated water and also in the components that are in-scope in accordance with 10 CFR 54.4(a)(2) criterion and listed in LRA Tables 3.3.2-13-xx series. The application also stated that there are no aluminum components with intended functions in the steam and power conversion systems.During the audit and review, the staff noted that for this aging effect, the One-Time InspectionProgram was not explicitly credited in the system table (Table 3.4.2-1), only the Water Chemistry Control-BWR Program was credited. In a letter dated July 14, 2006, the applicant amended the LRA. The applicant revised its Water Chemistry Control-BWR Program to include the sentence:
"The One-Time Inspection Program will confirm the effectiveness of the program."The staff reviewed the applicant's Water Chemistry Control - BWR Program and the One-TimeInspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff finds that the applicant's Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130).
The staff also finds that the applicant's One-Time Inspection Program is used to verify the effectiveness of the Water Chemistry Control-BWR Program consistent with the GALL Report and therefore acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
3-3763.4.2.1.6  Loss of Material Due to General, Pitting, and Crevice Corrosion and Loss of PreloadDue to Thermal Effects, Gasket Creep and Self-LooseningIn the discussion column of LRA Table 3.4.1, Item 3.4.1-22, the applicant stated that its SystemWalkdown Program will manage loss of material for steel bolting through the use of visual inspections performed at least once per refueling cycle. The applicant further stated that loss of preload is not an applicable aging effect. Loss of preload is a design driven effect and not an AERM. During the audit and review, the staff asked the applicant to clarify the basis for using its SystemWalkdown Program to manage the loss of material for steel bolting instead the AMP recommended by the GALL Report. In a letter dated July 6, 2006, the applicant stated that it will prepare and submit an AMP consistent with GALL AMP XI.M18, "Bolting Integrity," for approval. By letter dated October 17, 2006, the applicant provided its Bolting Integrity Program. The staffreviewed the applicant's Bolting Integrity Program and its evaluation is documented in SER Section 3.0.3.2.19. The staff finds that the applicant's Bolting Integrity Program conformed to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI. On this basis, the staff finds the applicant's Bolting Integrity Program acceptable for managing loss of material for steel bolting. In its October 17, 2006 letter, the applicant also stated that this program applies to all boltingexposed to air with aging effects requiring management, except reactor vessel closure studs.
However, in LRA, the applicant stated that loss of preload is not an applicable aging effect and does not requiring an aging management. The applicant was asked to confirm if the program applied to all bolting. By letter dated January 4, 2007, the applicant clarifying that the Bolting Integrity Program applies to bolting and torqueing practices of safety-related and nonsafety-related bolting for pressure retaining components, NSSS support components, and structural joints. On the basis of its review, the staff finds the applicant clarification acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.4.2.1.7  Loss of Material Due to General Corrosion In the discussion column of LRA Table 3.4.1, Item 3.4.1-28, the applicant stated that this item isconsistent with the GALL Report and that its System Walkdown Program will be used to manage loss of material for external surfaces of steel components.The staff reviewed the applicant's System Walkdown Program and its evaluation is documentedin SER Section 3.0.3.1.9. This program entails inspections of external surfaces of components subject to an AMR. The program is also credited with managing loss of material from internal surfaces where internal and external material-environment combinations are the same and external surface conditions represent internal surface conditions. The staff finds that the applicant's System Walkdown Program is consistent with GALL AMP XI.M36.
3-377On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.4.2.1.8  Wall Thinning Due to Flow-Accelerated Corrosion In the discussion column of LRA Table 3.4.1, Item 3.4.1-29, the applicant stated that this item isconsistent with the GALL Report and that its Flow-Accelerated Corrosion Program manages loss of material in steel components exposed to steam. The applicant further stated that there are no steel components exposed to treated water with the intended function in the steam and power conversion systems.The staff reviewed the applicant's Flow-Accelerated Corrosion Program and its evaluation isdocumented in SER Section 3.0.3.1.2. The staff also confirmed that LRA Table 3.4.2-1 has corresponding AMR line items for carbon steel components exposed to steam greater than
 
270F.Consistent with the GALL Reports recommendations, the applicant credits the Flow-AcceleratedCorrosion Program for managing loss of material from carbon steel piping, piping components, and piping elements exposed to steam or treated water. The staff finds this acceptable.3.4.2.1.9  Loss of Material Due to General, Pitting, and Crevice Corrosion In the discussion column of LRA Table 3.4.1, Item 3.4.1-30, the applicant stated that this item isconsistent with the GALL Report and that its System Walkdown Program will be used to manage loss of material for steel components internally exposed to outdoor air (internal) or condensation (internal). The applicant further stated that for systems where internal carbon steel surfaces are exposed to the same environment as external surfaces, the external surfaces condition will be representative of the internal surfaces; thus, a loss of material on internal carbon steel surfaces can be managed by its System Walkdown Program. The applicant also stated that LRA Table 3.4.1, Item 3.4.1-30 is applicable to component types listed in LRA Table 3.3.2.During the audit and review, the staff asked the applicant to clarify the basis for using theSystem Walkdown Program to manage loss of material for steel components internally exposed to outdoor air (internal) or condensation (internal) instead of an AMP consistent with GALL AMP XI.M38, as recommended by the GALL Report. In a letter dated July 14, 2006, the applicant revised its System Walkdown Program to addenhancements to the program's implementing procedure. Specifically, the applicant committed in Commitment #24 and Commitment #35, to have: (1) the System Walkdown guidance document enhanced to perform periodic system engineer inspections of systems in-scope and subject to an AMR for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3).
Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject system will include SSCs that are in-scope and subjected to an AMR for license renewal in accordance with 10 CFR 54.4 (a)(2); and (2) to provide within the System Walkdown Training Program a process to document biennial refresher training of Engineers to demonstrate inclusion of the methodology for agingmanagement of plant equipment as described in EPRI Aging Assessment Field Guide or comparable instructional guide.
3-378With this change, the applicant's management of steel components internally exposed tooutdoor air or condensation will be consistent with the GALL Report and therefore acceptable to the staff.The staff reviewed the applicant's System Walkdown Program and its evaluation is documentedin SER Section 3.0.3.1.9. This program entails inspections of external surfaces of components subject to an AMR. The program is also credited with managing loss of material from internal surfaces where internal and external material-environment combinations are the same and external surface conditions represent internal surface conditions. During interviews with the applicant's technical personnel, the staff confirmed that the applicant will use its System Walkdown Program and noted that coverage includes all elements as presented in the GALL Report's recommended program and therefore it is acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.4.2.1.10  Loss of Material Due to General, Pitting, Crevice, Galvanic, andMicrobiologically-Influenced Corrosion and FoulingFor loss of material due to fouling and general, pitting, crevice, galvanic, and MIC in steel heatexchanger components exposed to raw water; the GALL Report recommends programs consistent with GALL AMP XI.M20, "Open-Cycle Cooling Water System."In the discussion column of LRA Table 3.4.1, Item 3.4.1-31, the applicant stated that forcomponents of the CW system, its Periodic Surveillance and Preventive Maintenance Program, which is a plant-specific AMP, manages loss of material for steel heat exchanger components exposed to raw water through periodic visual inspections. Moreover, the CW system components to which this GALL Report line item applies are included in-scope for the steam and power conversion systems in accordance with 10 CFR 54.4(a)(2) criterion and listed in accordance with ESF system in LRA Tables 3.3.2-13-xx series.The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Programand its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1.This program includes periodic inspections and tests that manage aging effects not managed by other AMPs. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. On this basis, the staff determines that loss of material for carbon steel piping, pump casing, valve body, and copper alloy tubing is adequately managed using the Periodic Surveillance and Preventive Maintenance Program.The staff also confirmed that the applicant is managing these components in the LRATables 3.3.2-13-xx series using the Periodic Surveillance and Preventive Maintenance Program inspection. On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
3-3793.4.2.1.11  Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced CorrosionIn the discussion column of LRA Table 3.4.1, Item 3.4.1-32, the applicant stated that its PeriodicSurveillance and Preventive Maintenance Program manages loss of material for copper alloy components exposed to raw water through periodic visual inspections. The applicant further stated that there are no stainless steel components exposed to raw water with an intended function of pressure boundary in the steam and power conversion systems. The only components to which this GALL Report line item applies are included in-scope for the steam and power conversion systems in accordance with 10 CFR 54.4(a)(2) criterion and listed in accordance with the ESF system in LRA Tables 3.3.2-13-xx series.During the audit and review, the staff reviewed the applicant's Periodic Surveillance andPreventive Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.5.
Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for loss of material for copper alloy components exposed to raw water through periodic visual inspections. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.4.1, Item 3.4.1-32 in the population that is subject to the Periodic Surveillance and Preventive Maintenance Program inspection. This is consistent with the GALLReport and therefore acceptable to the staff.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.4.2.1.12  Loss of Material Due to Pitting, and Crevice Corrosion In the discussion column of LRA Table 3.4.1, Item 3.4.1-37, the applicant stated that its WaterChemistry Control - BWR Program will be used to manage loss of material in stainless steel and steel components in its steam and power conversion systems. The applicant further states that there are no nickel alloy components exposed to steam in the steam and power conversion systems.The staff reviewed the applicant's Water Chemistry Control - BWR Program and its evaluation isdocumented in SER Section 3.0.3.1.11. The staff finds that the applicant's Water Chemistry -
BWR Program manages aging effects caused by corrosion and cracking mechanisms. The program monitors and controls water chemistry in accordance with the EPRI report. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.4.1, Item 3.4.1-37 in the population that is subject to the Chemistry Control-BWR Program. This is consistent with the GALL Report and therefore acceptable to the staff.For loss of material due to pitting and crevice corrosion from steel, stainless steel, andnickel-based alloy piping, piping components, and piping elements exposed to steam; the GALLReport recommends programs consistent with GALL AMP XI.M2, "Water Chemistry."
3-380In the discussion column of LRA Table 3.4.1, Item 3.4.1-37, the applicant stated that its WaterChemistry Control-Auxiliary Systems Program will be used to manage loss of material in stainless steel, nickel-based alloy, and steel components in its HVAC system componentsexposed to steam from the applicant's house heating boiler system.During the audit and review, the staff noted that for this aging effect, the GALL Report'srecommended Water Chemistry Control-Auxiliary Systems Program was not explicitly identified in the system table (Table 3.4.2.-1). The staff reviewed the applicant's Water Chemistry Control-Auxiliary Systems Program and its evaluation is documented in SER Section 3.0.3.3.7 The applicant's Water Chemistry Control-Auxiliary Systems Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1.This program manages aging effects for components exposed to treated water. On this basis, the staff finds that loss of material in stainless steel, nickel-based alloy, and steel components in its HVAC system componentsexposed to steam is adequately managed using the Water Chemistry Control-Auxiliary Systems Program.During interviews with the applicant's technical personnel, the staff confirmed that the applicantincluded all components in LRA Table 3.4.1, Item 3.4.1-37 in the population that is subject to the Chemistry Control-Auxiliary Systems Program.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed consistent with its AMRs. Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.4.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is RecommendedSummary of Information in the Application. In LRA Section 3.4.2.2, the applicant furtherevaluates aging management, as recommended by the GALL Report, for the steam and power conversion systems components and provides information concerning how it will manage the following aging effects:
* cumulative fatigue damage
* loss of material due to general, pitting, and crevice corrosion
* loss of material due to general, pitting, crevice, and microbiologically-induced corrosion,and fouling
* reduction of heat transfer due to fouling
* loss of material due to general, pitting, crevice, and microbiologically-induced corrosion 3-381
* cracking due to stress-corrosion cracking
* loss of material due to pitting and crevice corrosion
* loss of material due to pitting, crevice, and microbiologically-induced corrosion
* loss of material due to general, pitting, crevice, and galvanic corrosion
* quality assurance for aging management of nonsafety-related componentsStaff Evaluation. For component groups evaluated in the GALL Report, for which the applicantclaimed consistency with the report and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations against the criteria contained in SRP-LR Section 3.4.2.2. The staff's review of the applicant's further evaluation follows.3.4.2.2.1  Cumulative Fatigue Damage LRA Section 3.4.2.2.1 states that fatigue is a TLAA, as required by 10 CFR 54.3. Applicantsmust evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.3.4.2.2.2  Loss of Material Due to General, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.4.2.2.2 against the following SRP-LR Section 3.4.2.2.2criteria:  (1)LRA Section 3.4.2.2.2 addresses the loss of material of carbon steel piping andcomponents exposed to treated water or steam due to general, pitting and crevice
 
corrosion.SRP-LR Section 3.4.2.2.2 states that loss of material due to general, pitting, and crevicecorrosion may occur in steel piping, piping components, piping elements, tanks, and heatexchanger components exposed to treated water and for steel piping, piping components, and piping elements exposed to steam. The existing AMP monitors and controls water chemistry to manage the effects of loss of material due to general, pitting, and crevice corrosion. However, control of water chemistry does not preclude loss of material due to general, pitting, and crevice corrosion at locations with stagnant flow conditions; therefore, the effectiveness of water chemistry control programs should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to verify the effectiveness of water chemistry control programs. A one-time inspection of select components and susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated, in the LRA, that loss of material due to general, pitting and crevicecorrosion for carbon steel piping and components exposed to treated water or steam is an AERM in the steam and power conversion systems at VYNPS, and is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicant's Water 3-382Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program,through an inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.4.2.2.2 and is therefore acceptable.  (2)LRA Section 3.4.2.2.2 addresses the loss of material of steel piping and components insteam and power conversion systems exposed to lubricating oil due to general, pitting, and crevice corrosion.
SRP-LR Section 3.4.2.2.2 states that loss of material due to general, pitting, and crevice corrosion may occur in steel piping, piping components, and piping elements exposed tolubricating oil. The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil contaminant control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of lube oil chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The staff finds that the steam and power conversion systems at VYNPS have no carbonsteel components with intended functions that are exposed to lubricating oil, therefore, this item is not applicable to VYNPS.On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.4.2.2.2 criteria. For those line items that apply to LRA Section 3.4.2.2.2, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.4.2.2.3  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-InfluencedCorrosion and FoulingThe staff reviewed LRA Section 3.4.2.2.3 against the criteria in SRP-LR Section 3.4.2.2.3.
LRA Section 3.4.2.2.3 addresses the loss of material due to general, pitting, crevice, MIC, andfouling. This aging effect is not applicable to VYNPS. Loss of material due to general, pitting, crevice, MIC, and fouling could occur in steel piping, piping components, and piping elementsexposed to raw water.
3-383SRP-LR Section 3.4.2.2.3 states that loss of material due to general, pitting, and crevicecorrosion, and MIC and fouling may occur in steel piping, piping components, and pipingelements exposed to raw water. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed.The staff finds that the steam and power conversion systems at VYNPS have no carbon steelcomponents with intended functions that are exposed to raw water, therefore, this item is not applicable to VYNPS.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.3.4.2.2.4  Reduction of Heat Transfer Due to Fouling The staff reviewed LRA Section 3.4.2.2.4 against the following SRP-LR Section 3.4.2.2.4criteria:  (1)LRA Section 3.4.2.2.4 addresses the reduction of heat transfer of stainless steel andcopper alloy heat exchanger tubes exposed to treated water due to fouling.SRP-LR Section 3.4.2.2.4 states that reduction of heat transfer due to fouling may occurin stainless steel and copper alloy heat exchanger tubes exposed to treated water. The existing AMP controls water chemistry to manage reduction of heat transfer due to fouling. However, control of water chemistry may not always be fully effective in precluding fouling; therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that reduction of heat transfer due to fouling does not occur. A one-time inspection is an acceptable method to ensure that reduction of heat transfer does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated in the LRA that reduction of heat transfer due to fouling could occurfor stainless steel and copper alloy heat exchanger tubes exposed to treated water. The steam and power conversion systems at VYNPS have no heat exchanger tubes with an intended function of heat transfer and associated aging effect of fouling. However, reduction of heat transfer is managed by the Water Chemistry Control-BWR Program, for copper alloy heat exchanger tubes in the HPCI and RCICSs. The effectiveness of the applicant's Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow. The staff finds this combination satisfies the criteria of SRP-LR Section 3.4.2.2.4 and is therefore acceptable.
3-384  (2)LRA Section 3.4.2.2.4 addresses the reduction of heat transfer of steel, stainless steel,and copper alloy heat exchanger tubes exposed to lubricating oil due to fouling.SRP-LR Section 3.4.2.2.4 states that reduction of heat transfer due to fouling may occurin steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil.
The existing AMP monitors and controls lube oil chemistry to mitigate reduction of heat transfer due to fouling. However, control of lube oil chemistry may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil contaminant control should be verified to ensure that fouling does not occur. The GALL Report recommends further evaluation of programs to verify the effectiveness of lube oil chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the component's intended functions will be maintained during the period of extended operation.The staff finds that the steam and power conversion systems at VYNPS have no heatexchanger tubes with an intended function of heat transfer and associated aging effect of fouling, therefore, this item is not applicable to VYNPS.On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.4.2.2.4 criteria. For those line items that apply to LRA Section 3.4.2.2.4, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.4.2.2.5  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-InfluencedCorrosionThe staff reviewed LRA Section 3.4.2.2.5 against the following SRP-LR Section 3.4.2.2.5criteria:  (1)LRA Section 3.4.2.2.5 addresses the loss of material due to general, pitting, crevicecorrosion, and MIC of carbon steel (with or without coating or wrapping) piping, piping components, piping elements and tanks exposed to soil.SRP-LR Section 3.4.2.2.5 states that loss of material due to general, pitting, and crevicecorrosion, and MIC may occur in steel (with or without coating or wrapping) piping, piping components, piping elements, and tanks exposed to soil. The buried piping and tanks inspection program relies on industry practice, frequency of pipe excavation, and operating experience to manage the effects of loss of material from general, pitting, and crevice corrosion, and MIC. The effectiveness of the buried piping and tanks inspection program should be verified to evaluate an applicant's inspection frequency and operating experience with buried components and to ensure that loss of material does not occur.
3-385The staff finds that the steam and power conversion systems at VYNPS have no carbonsteel components that are exposed to soil, therefore, this item is not applicable to
 
VYNPS.On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS.  (2)LRA Section 3.4.2.2.5 addresses the loss of material due to general, pitting, crevicecorrosion, and MIC of carbon steel heat exchanger components exposed to lubricating
 
oil.SRP-LR Section 3.4.2.2.5 states that loss of material due to general, pitting, and crevicecorrosion, and MIC may occur in steel heat exchanger components exposed to lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil contaminant control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of the lube oil chemistry control program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The staff finds that the steam and power conversion systems at VYNPS have no heatexchanger components with intended functions that are exposed to lubricating oil, therefore, this item is not applicable to VYNPS.On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS.3.4.2.2.6  Cracking Due to Stress Corrosion Cracking The staff reviewed LRA Section 3.4.2.2.6 against the criteria in SRP-LR Section 3.4.2.2.6.
LRA Section 3.4.2.2.6 addresses cracking of stainless steel components exposed to steam dueto SCC.SRP-LR Section 3.4.2.2.6 states that cracking due to SCC may occur in stainless steel piping,piping components, piping elements, tanks, and heat exchanger components exposed to treated water greater than 60 C (140 F) and in stainless steel piping, piping components, and pipingelements exposed to steam. The existing AMP monitors and controls water chemistry to manage the effects of cracking due to SCC. However, high concentrations of impurities in crevices and with stagnant flow conditions may cause SCC; therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that SCC does not occur. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that SCC does not occur and that component intended functions will be maintained during the period of extended operation.
3-386In LRA Table 3.4.1, Item 3.4.1-14 discussion column, the applicant stated that the cracking dueto SCC of stainless steel piping, piping components, tanks, and heat exchanger componentsexposed to treated water greater than 60C (greater than140F) is not applicable at VYNPS.The staff determined, through discussions with the applicant's technical personnel, that there are no stainless steel components exposed treated water with intended functions in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable to VYNPS.The applicant stated in the LRA that cracking due to SCC in stainless steel components exposedto steam is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicant's Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow. The staff finds this combination satisfies the criteria of SRP-LR Section 3.4.2.2.6 and is therefore acceptable.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.4.2.2.6 criteria. For those line items that apply to LRA Section 3.4.2.2.6, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.4.2.2.7  Loss of Material Due to Pitting and Crevice Corrosion The staff reviewed LRA Section 3.4.2.2.7 against the following SRP-LR Section 3.4.2.2.7criteria:  (1)LRA Section 3.4.2.2.7 addresses the loss of material of copper alloy componentsexposed to treated water due to pitting and crevice corrosion.SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice corrosionmay occur in stainless steel, aluminum, and copper alloy piping, piping components, andpiping elements and in stainless steel tanks and heat exchanger components exposed to treated water. The existing AMP monitors and controls water chemistry to manage the effects of loss of material due to pitting and crevice corrosion. However, control of water chemistry may not preclude corrosion at locations with stagnant flow conditions; therefore, the GALL Report recommends that the effectiveness of water chemistry programs should be verified to ensure that corrosion does not occur. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The applicant stated in the LRA that loss of material due to pitting and crevice corrosionfor copper alloy components exposed to treated water is managed by the Water Chemistry Control-BWR Program. The steam and power conversion systems at VYNPS have no stainless steel components with intended functions that are exposed to treated water (Table 3.4-1, Item 3.4.1-16). There are no aluminum components in the steam and power conversion systems. The effectiveness of the applicant's Water Chemistry 3-387Control-BWR Program will be confirmed by the One-Time Inspection Program, throughan inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow. The staff finds this combination satisfies the criteria of SRP-LR Section 3.4.2.2.7 and is therefore acceptable.  (2)LRA Section 3.4.2.2.7 addresses loss of material due to pitting and crevice corrosion ofstainless steel piping, piping components, and piping elements exposed to soil.SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice corrosionmay occur in stainless steel piping, piping components, and piping elements exposed tosoil. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed.The staff finds that the steam and power conversion systems at VYNPS have nostainless steel components with intended function that are exposed to soil, therefore, this item is not applicable to VYNPS.On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS.  (3)LRA Section 3.4.2.2.7 addresses the loss of material due to pitting and crevice corrosionof copper alloy piping, piping components, and piping elements exposed to lubricating oil.SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice corrosionmay occur in copper alloy piping, piping components, and piping elements exposed to lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil contaminant control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of the lube oil chemistry control program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The staff finds that the steam and power conversion systems at VYNPS have no copperalloy components with intended functions that are exposed to lubricating oil, therefore, this item is not applicable to VYNPS.On the basis that VYNPS does not have any components from this group, the staff findsthat this aging effect is not applicable to VYNPS.
3-388Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.4.2.2.7 criteria. For those line items that apply to LRA Section 3.4.2.2.7, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.4.2.2.8  Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion The staff reviewed LRA Section 3.4.2.2.8 against the criteria in SRP-LR Section 3.4.2.2.8.
LRA Section 3.4.2.2.8 addresses the loss of material due to pitting, crevice, and MIC of stainlesssteel piping, piping components, piping elements, and heat exchanger components exposed tolubricating oil.SRP-LR Section 3.4.2.2.8 states that loss of material due to pitting and crevice corrosion, andMIC may occur in stainless steel piping, piping components, piping elements, and heatexchanger components exposed to lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil contaminant control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of the lube oil chemistry control program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The staff finds that the steam and power conversion systems at VYNPS have no stainless steelcomponents with intended functions that are exposed to lubricating oil, therefore, this item is not applicable to VYNPS.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.3.4.2.2.9  Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion The staff reviewed LRA Section 3.4.2.2.9 against the criteria in SRP-LR Section 3.4.2.2.9.
LRA Section 3.4.2.2.9 addresses the loss of material due to general, pitting, crevice, andgalvanic corrosion of steel heat exchanger components exposed to treated water.SRP-LR Section 3.4.2.2.9 states that loss of material due to general, pitting, crevice, andgalvanic corrosion may occur in steel heat exchanger components exposed to treated water.
The existing AMP monitors and controls water chemistry to manage the effects of loss of material due to general, pitting, and crevice corrosion. However, control of water chemistry does not preclude loss of material due to general, pitting, and crevice corrosion at locations with stagnant flow conditions; therefore, the effectiveness of water chemistry control programs should 3-389be verified to ensure that corrosion does not occur. The GALL Report recommends furtherevaluation of programs to verify the effectiveness of water chemistry control programs. A one-time inspection of select components and susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation.The staff finds that the steam and power conversion systems at VYNPS have no steel heatexchanger components with intended functions that are exposed to treated water, therefore, this item is not applicable to VYNPS.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.3.4.2.2.10  Quality Assurance for Aging Management of Nonsafety-Related Components SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program, which thestaff found acceptable.3.4.2.3  AMR Results Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Table 3.4.2-1, the staff reviewedadditional details of the AMR results for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report. These items were reviewed and they are further addressed in SER Section 3.4.2.3.In LRA Table 3.4.2-1, the applicant indicated, via notes F through J, that the combination ofcomponent type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information about how it will manage the aging effects. Specifically, note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.Staff Evaluation. For component type, material, and environment combinations not evaluated inthe GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff's evaluation is documented in the following sections.
3-3903.4.2.3.1  Main Condenser and MSIV Leakage Pathway Summary of Aging ManagementEvaluation-LRA Table 3.4.2-1The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for themain condenser and MSIV leakage pathway component groups.In LRA Table 3.4.2-1, the applicant proposed to manage cracking-fatigue of condensercomponents (stainless steel heat exchanger tubes, thermowells, tubing, and valve bodies exposed to steam greater than270F (internal) using a TLAA-metal fatigue.The staff's review of the TLAA is documented in SER Section 4.3.
3.4.2.3.2  Aging Effect/Mechanism in Table 3.4.1 Which Are Not Applicable for VYNPS The staff reviewed LRA Table 3.4.1, which provides a summary of aging managementevaluations for the steam and power conversion systems evaluated in the GALL Report.In LRA Table 3.4.1, Item 3.4.1-20 discussion column, the applicant stated that loss of material ofsteel tanks exposed to air outdoor (external) due to general, pitting, and crevice corrosion is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no steel tanks exposed to outdoor air with intended functions in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS.In LRA Table 3.4.1, Item 3.4.1-21 discussion column, the applicant stated that cracking of highstrength steel closure bolting exposed to air with steam or water leakage due to cyclic loadingand SCC is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that high strength steel closure bolting is not used in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable to VYNPS.In LRA Table 3.4.1, Item 3.4.1-23 discussion column, the applicant stated that the cracking ofstainless steel piping, piping components, and piping elements exposed to closed cycle coolingwater greater than60C (greater than140F) due to SCC is not applicable at VYNPS. The staffdetermined, through discussions with the applicant's technical personnel, that there are no stainless steel components with intended functions exposed to close-cycle cooling water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable to VYNPS.In LRA Table 3.4.1, Item 3.4.1-24 discussion column, the applicant stated that the loss ofmaterial of steel heat exchanger components exposed to closed-cycle cooling water due to general, pitting, crevice, and galvanic corrosion is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no steel heat exchanger components with intended functions exposed to closed-cycle cooling water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS.
3-391In LRA Table 3.4.1, Item 3.4.1-26 discussion column, the applicant stated that the loss ofmaterial of copper alloy piping, piping components, and piping elements exposed to closed-cyclecooling water due to pitting, crevice, and galvanic corrosion is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no copper alloy components with intended functions exposed to closed-cycle cooling water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS. In LRA Table 3.4.1, Item 3.4.1-27 discussion column, the applicant stated that the reduction ofheat transfer of steel, stainless steel, and copper alloy heat exchanger tubes exposed to closed-cycle cooling water due to fouling is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no heat exchanger tubes with intended functions exposed to closed-cycle cooling water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS. In LRA Table 3.4.1, Item 3.4.1-33 discussion column, the applicant stated that the loss ofmaterial of stainless steel heat exchanger components exposed to raw water due to fouling and pitting, crevice, and MIC is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no stainless steel heat exchanger components with intended functions exposed to raw water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS.In LRA Table 3.4.1, Item 3.4.1-34 discussion column, the applicant stated that the reduction ofheat transfer of steel, stainless steel, and copper alloy heat exchanger tubes exposed to raw water due to fouling is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no heat exchanger tubes with intended functions exposed to raw water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS.In LRA Table 3.4.1, Item 3.4.1-35 discussion column, the applicant stated that the loss ofmaterial of copper alloy greater than15 percent Zinc piping, piping components, and pipingelements exposed to closed-cycle cooling water, raw water, or treated water due to selective leaching is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that the there are no copper alloy with intended functions and subject to selective leaching in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS.In LRA Table 3.4.1, Item 3.4.1-36 discussion column, the applicant stated that the loss ofmaterial of gray cast iron piping, piping components, and piping elements exposed to soil,treated water, or raw water due to selective leaching is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no gray cast iron components with intended functions exposed to raw water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS.
3-3923.4.2.3.3  Steam and Power Conversion Systems AMR Line Items That Have No AgingEffects-LRA Table 3.4.2-1The applicant, in LRA Notes for Table 3.4.2-1, Plant-Specific Notes 401, stated: Aging management of the main condenser is not based on analysis of materials,environments and aging effects. Condenser integrity required to perform the post-accident intended function (holdup and plateout of MSIV leakage) is continuously confirmed by normal plant operation. This intended function does not require the condenser to be leak-tight, and the post-accident conditions in the condenser will be essentially atmospheric. Since normal plant operation assures adequate condenser pressure boundary integrity, the post-accident intended function to provide holdup volume and plateout surface is assured. Based on past precedence (NUREG-1796, Dresden and Quad Cities SER Section 3.4.2.4.4, and NUREG-1769, Peach Bottom SER Section 3.4.2.3), the staff concludes that main condenser integrity is continually verified during normal plant operation and no AMP is required to assure the post-accident intended function. The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for themain condenser and MSIV leakage pathway component groups.In LRA Table 3.4.2-1, the applicant proposed to verify the integrity of the following condensercomponents with the specified material/environment combinations during normal plant operations:
Carbon steel exposed to air (indoor-external)
Carbon steel exposed to steam greater than 270F    Copper alloy greater than15 percent zinc (inhibited) exposed to raw water Copper alloy greater than15 percent zinc (inhibited) exposed to steam greater than 270F    Stainless steel exposed to raw water Stainless steel exposed to steam greater than 270FOn the basis of its review, the staff finds that above environment and material combinations, ifmanaged during normal plant operations, will not result in aging that would be of concern during the period of extended operation. The staff noted that the plateout function of the condenser will be retained and further concludes that there are no applicable AERM for the above environment and material combinations. On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-3933.4.3  ConclusionThe staff concludes that the applicant has provided sufficient information to demonstrate that theeffects of aging for the steam and power conversion systems components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.5  Aging Management of SC SupportsThis section of the SER documents the staff's review of the applicant's AMR results for the SC supports components and component groups of:
* primary containment
* reactor building
* intake structure
* process facilities
* yard structures
* bulk commodities3.5.1  Summary of Technical Information in the ApplicationLRA Section 3.5 provides AMR results for the SC supports components and component groups.LRA Table 3.5.1, "Summary of Aging Management Evaluations for the Structures and Component Supports," is a summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the SC supports components and component groups.The applicant's AMRs evaluated and incorporated applicable plant-specific and industryoperating experience in the determination of AERMs. The plant-specific evaluation included condition reports and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.3.5.2  Staff EvaluationThe staff reviewed LRA Section 3.5 to determine whether the applicant provided sufficientinformation to demonstrate that the effects of aging for the SC supports components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRswere consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's audit evaluation are documented in SER Section 3.5.2.1.
3-394In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for whichfurther evaluation is recommended. The staff confirmed that the applicant's further evaluations were consistent with the SRP-LR Section 3.5.2.2 acceptance criteria. The staff's audit evaluations are documented in SER Section 3.5.2.2.The staff also conducted a technical review of the remaining AMRs that were not consistent with,or not addressed in, the GALL Report. The technical review evaluated whether all plausible aging effects have been identified and whether the aging effects listed were appropriate for the material-environment combinations specified. The staff's evaluations are documented in SER Section 3.5.2.3.For SSCs which the applicant claimed were not applicable or required no aging management,the staff reviewed the AMR line items and the plant's operating experience to verify the applicant's claims.Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensurethat they provided an adequate description of the programs credited with managing or monitoring aging for the structures and component supports components.Table 3.5-1 summarizes the staff's evaluation of components, aging effects/mechanisms, andAMPs listed in LRA Section 3.5 and addressed in the GALL Report.Table 3.5-1  Staff Evaluation for SC Supports in the GALL ReportComponent Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation BWR Concrete and Steel (Mark I, II, and III) ContainmentsConcrete elements:walls, dome, basemat, ring
 
girder, buttresses, containment (as applicable).
 
(3.5.1-1)Aging of accessible and inaccessible
 
concrete areas due to aggressive
 
chemical attack, and corrosion of
 
embedded steelISI (IWL) and for inaccessible
 
concrete, an examination of representative
 
samples of below-grade
 
concrete, and
 
periodic monitoring of groundwater if environment is non-aggressive. A
 
plant-specific
 
program is to be evaluated if environment is aggressive.NoneNot applicable.(VYNPS containment is a Mark I steel
 
containment.)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-395Concrete elements; All (3.5.1-2)Cracks and distortion due to
 
increased stress levels from
 
settlement StructuresMonitoring Program.
If a de-watering system is relied
 
upon for control of
 
settlement, then the
 
applicant is to
 
ensure proper
 
functioning of the de-watering system
 
through the period of extended
 
operation.NoneNot applicable.(VYNPS containment is a Mark I steel
 
containment.)Concrete elements:
foundation, subfoundation
 
(3.5.1-3)Reduction in foundation strength, cracking, differential
 
settlement due to
 
erosion of porous
 
concrete subfoundation StructuresMonitoring Program If a de-watering system is relied
 
upon to control
 
erosion of cement
 
from porous
 
concrete subfoundations, then the applicant is
 
to ensure proper
 
functioning of the de-watering system
 
through the period of extended
 
operation.NoneNot applicable.(VYNPS containment is a Mark I steel
 
containment.)Concrete elements:dome, wall, basemat, ring
 
girder, buttresses, containment, concrete fill-in
 
annulus (as applicable)
 
(3.5.1-4)Reduction of strength and
 
modulus of concrete due to elevated
 
temperature A plant-specificAMP is to be evaluatedNoneNot applicable.(VYNPS containment is a Mark I steel
 
containment.)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-396 Steel elements:Drywell; torus; drywell head;
 
embedded shell and
 
sand pocket regions; drywell
 
support skirt; torus
 
ring girder; downcomers; liner plate, ECCS suction
 
header, support
 
skirt, region
 
shielded by
 
diaphragm floor, suppression
 
chamber (as applicable)
 
(3.5.1-5)Loss of material due to general, pitting and crevice corrosionISI (IWE) and10 CFR 50, Appendix JContainmentInservice Inspection
 
Program (B.1.15.1);
Containment Leak Rate Program (B.1.8)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.5.2.2.1
 
under the heading, "Loss of Material Due to General, Pitting and Crevice Corrosion")
Steel elements:
steel liner, liner
 
anchors, integral
 
attachments
 
(3.5.1-6)Loss of material due to general, pitting and crevice corrosionISI (IWE) and10 CFR 50, Appendix JNoneNot applicable.(VYNPS containment is a Mark I steel
 
containment.)
Prestressed containment
 
tendons (3.5.1-7)Loss of prestressdue to relaxation, shrinkage, creep, and elevated
 
temperatureTLAA, evaluated inaccordance with 10 CFR 54.21(c)NoneNot applicable.(VYNPS containment is a Mark I steel
 
containment.)
Steel and stainlesssteel elements: vent line, vent header, vent line bellows; downcomers;
 
(3.5.1-8)Cumulative fatiguedamage (CLB fatigue analysis exists)TLAA, evaluated inaccordance with 10 CFR 54.21(c)NoneNot applicable. (See SER Section 3.5.2.2.1
 
under the heading, "Cumulative Fatigue Damage")Steel, stainless steel elements, dissimilar metal welds: penetration sleeves, penetration bellows; suppression pool
 
shell, unbraced downcomers
 
(3.5.1-9)Cumulative fatiguedamage (CLB fatigue analysis exists)TLAA, evaluated inaccordance with 10 CFR 54.21(c)NoneFatigue is a TLAA.(See Section SER
 
3.5.2.2.1 under the
: heading, "Cumulative Fatigue Damage," and SER
 
Section and 4.6)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-397 Stainless steelpenetration sleeves, penetration bellows, dissimilar metal welds (3.5.1-10)Cracking due to SCCISI (IWE) and10 CFR 50, Appendix J, and
 
additional
 
appropriate examinations/
evaluations for bellows assemblies
 
and dissimilar metal welds.NoneNot applicable (See SER Section 3.5.2.2.1
 
under the heading, "Cracking Due to
 
SCC")Stainless steel ventline bellows, (3.5.1-11)Cracking due to SCCISI (IWE) and10 CFR 50, Appendix J, and
 
additional
 
appropriate examination/
evaluation for bellows assemblies
 
and dissimilar metal welds.NoneNot applicable (See SER Section 3.5.2.2.1
 
under the heading, "Cracking Due to
 
SCC")Steel, stainless steel elements, dissimilar metal welds: penetration sleeves, penetration bellows; suppression pool
 
shell, unbraced downcomers
 
(3.5.1-12)Cracking due tocyclic loadingISI (IWE) and10 CFR 50, Appendix J, and
 
supplemented to
 
detect fine cracksContainmentInservice Inspection
 
Program (B.1.15.1);
Containment Leak Rate Program (B.1.8)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.5.2.2.1
 
under the heading, "Cracking Due to Cyclic Loading")
Steel, stainless steel elements, dissimilar metal welds: torus; vent line; vent header; vent line bellows; downcomers
 
(3.5.1-13)Cracking due tocyclic loadingISI (IWE) and10 CFR 50, Appendix J, and
 
supplemented to
 
detect fine cracksContainmentInservice Inspection
 
Program (B.1.15.1);
Containment Leak
 
Rate Program (B.1.8)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.5.2.2.1
 
under the heading, "Cracking Due to Cyclic Loading")Concrete elements:dome, wall, basemat ring girder, buttresses, containment (as applicable)
 
(3.5.1-14)
Loss of material(Scaling, cracking, and spalling) due to freeze-thawISI (IWL).Evaluation is
 
needed for plants
 
that are located in moderate to severe weathering
 
conditions (weathering index > 100 day-inch/yr)
(NUREG-1557).NoneNot applicable.(VYNPS containment is a Mark I steel
 
containment.)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-398Concrete elements:walls, dome, basemat, ring
 
girder, buttresses, containment, concrete fill-in
 
annulus (as applicable).
 
(3.5.1-15)Cracking due toexpansion and reaction with
 
aggregate; increase in porosity, permeability due to
 
leaching of calcium hydroxideISI (IWL) for accessible areas.
None for inaccessible areas if concrete was
 
constructed in accordance with the
 
recommendations in ACI 201.2R.NoneNot applicable.(VYNPS containment is a Mark I steel
 
containment.)
Seals, gaskets, andmoisture barriers
 
(3.5.1-16)
Loss of sealing and leakage through
 
containment due to
 
deterioration of joint
 
seals, gaskets, and moisture barriers (caulking, flashing, and other sealants)ISI (IWE) and10 CFR 50, Appendix JContainmentInservice Inspection
 
Program (B.1.15.1);
Containment Leak
 
Rate Program (B.1.8)Consistent with theGALL Report.
(See SER Section 3.5.2.1.4)
Personnel airlock, equipment hatch and CRD hatch
 
locks, hinges, and
 
closure mechanisms
 
(3.5.1-17)
Loss of leak tightness in closed
 
position due to mechanical wear of
 
locks, hinges and
 
closure mechanisms10 CFR 50,Appendix J and Plant TSsNoneNot applicable. (See SER Section 3.5.2.1.5)
Steel penetrationsleeves and dissimilar metal welds; personnel
 
airlock, equipment hatch and CRD
 
hatch (3.5.1-18)
Loss of material due to general, pitting, and crevice corrosionISI (IWE) and10 CFR 50, Appendix JContainmentInservice Inspection
 
Program (B.1.15.1);
Containment Leak Rate Program (B.1.8)Consistent withGALL Report,(See
 
SER Section 3.5.2.1.6)
Steel elements:
stainless steel
 
suppression
 
chamber shell (inner
 
surface)
(3.5.1-19)Cracking due to SCCISI (IWE) and10 CFR 50, Appendix JNoneNot applicable. (TheVYNPS suppression
 
chamber is carbon
 
steel.)Steel elements:
suppression
 
chamber liner (interior surface)
 
(3.5.1-20)
Loss of material due to general, pitting, and crevice corrosionISI (IWE) and10 CFR 50, Appendix JNoneNot applicable. (TheVYNPS suppression
 
chamber is carbon
 
steel.)Steel elements:drywell head and downcomer pipes
 
(3.5.1-21)
Fretting or lock up due to mechanical wearISI (IWE)NoneNot applicable (See SER Section 3.5.2.1.7)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-399 Prestressed containment:
 
tendons and
 
anchorage components
 
(3.5.1-22)
Loss of material dueto corrosionISI (IWL)NoneNot applicable.(VYNPS containment is a Mark I steel containment without
 
prestressed
 
tendons.)Safety-Related and Other Structures; and Component SupportsAll Groups exceptGroup 6: interior and above grade exterior concrete
 
(3.5.1-23)Cracking, loss of bond, and loss of
 
material (spalling, scaling) due to
 
corrosion of
 
embedded steel StructuresMonitoring Program StructuresMonitoring Program (B.1.27.2)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.5.2.2.2
 
under the heading, "Aging of Structures Not Covered by Structures Monitoring
 
Program," item 1)All Groups exceptGroup 6: interior and above grade exterior concrete
 
(3.5.1-24)
Increase in porosityand permeability, cracking, loss of
 
material (spalling, scaling) due to aggressive chemical
 
attack StructuresMonitoring ProgramStructures Monitoring Program (B.1.27.2)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Section 3.5.2.2.2
 
under the heading, "Aging of Structures Not Covered by Structures Monitoring Program," item 2
)All Groups exceptGroup 6: steel
 
components: all
 
structural steel
 
(3.5.1-25)
Loss of material dueto corrosion StructuresMonitoring Program.
If protective
 
coatings are relied
 
upon to manage the
 
effects of aging, the structures
 
monitoring program
 
is to include provisions to address protective
 
coating monitoring
 
and maintenance.Structures Monitoring Program (B.1.27.2);
Periodic Surveillance and Preventive Maintenance
 
Program (B.1.22);
 
Fire Protection
 
Program (B.1.12.1)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Section 3.5.2.2.2
 
under the heading, "Aging of Structures Not Covered by Structures Monitoring
 
Program," item 3)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-400All Groups exceptGroup 6: accessible
 
and inaccessible
 
concrete: foundation
 
(3.5.1-26)
Loss of material (spalling, scaling)
 
and cracking due to freeze-thaw StructuresMonitoring Program.
Evaluation is
 
needed for plants
 
that are located in moderate to severe weathering
 
conditions (weathering index
> 100 day-inch/yr)
(NUREG-1557).Structures Monitoring Program (B.1.27.2)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Section 3.5.2.2.2
 
under the heading, "Aging of Structures Not Covered by Structures Monitoring Program," item 4
)All Groups exceptGroup 6: accessible
 
and inaccessible interior/exterior
 
concrete (3.5.1-27)Cracking due toexpansion due to reaction with
 
aggregates StructuresMonitoring Program.
None for inaccessible areas if concrete was
 
constructed in accordance with the
 
recommendations in ACI 201.2R-77.Structures Monitoring Program (B.1.27.2)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Section 3.5.2.2.2
 
under the heading, "Aging of Structures Not Covered by Structures Monitoring
 
Program," item 5)Groups 1-3, 5-9: All (3.5.1-28)Cracks and distortion due to
 
increased stress levels from
 
settlement StructuresMonitoring Program.
If a de-watering system is relied
 
upon for control of
 
settlement, then the
 
applicant is to
 
ensure proper
 
functioning of the de-watering system
 
through the period of extended
 
operation.NoneNot applicable. (See SER Section 3.5.2.2.2
 
under the heading, "Aging of Structures Not Covered by Structures Monitoring
 
Program," item 6)Groups 1-3, 5-9:
foundation
 
(3.5.1-29)Reduction in foundation strength, cracking, differential
 
settlement due to
 
erosion of porous
 
concrete subfoundation StructuresMonitoring Program.
If a de-watering system is relied
 
upon for control of
 
settlement, then the
 
applicant is to
 
ensure proper
 
functioning of the de-watering system
 
through the period of extended
 
operation.NoneNot applicable. (See SER Section 3.5.2.2.2
 
under the heading, "Aging of Structures Not Covered by Structures Monitoring
 
Program," item 7)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-401Group 4: Radialbeam seats in BWR drywell; RPV
 
support shoes for PWR with nozzle
 
supports; Steam
 
generator supports
 
(3.5.1-30)Lock-up due to wearISI (IWF) or Structures Monitoring Program StructuresMonitoring Program (B.1.27.2)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.5.2.2.2
 
under the heading, "Aging of Structures Not Covered by Structures Monitoring
 
Program," item 8)Groups 1-3, 5, 7-9:below-grade
 
concrete components, such as exterior walls below grade and
 
foundation
 
(3.5.1-31)
Increase in porosityand permeability, cracking, loss of
 
material (spalling, scaling)/aggressive
 
chemical attack; Cracking, loss of
 
bond, and loss of
 
material (spalling, scaling)/corrosion of
 
embedded steel Structures monitoring Program; Examination of representative
 
samples of below-grade
 
concrete, and
 
periodic monitoring of groundwater, if the environment is non-aggressive. A
 
plant-specific
 
program is to be evaluated if environment is aggressive.
Buried Piping Inspection Program (B.1.1); Structures Monitoring Program (B.1.27.2)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.5.2.2.2
 
under the heading, "Aging Management
 
of Inaccessible
 
Areas")Groups 1-3, 5, 7-9:exterior above and below grade
 
reinforced concrete
 
foundations
 
(3.5.1-32)
Increase in porosityand permeability, and loss of strength
 
due to leaching of calcium hydroxide StructuresMonitoring Program for accessible areas. None for
 
inaccessible areas if concrete was
 
constructed in accordance with the
 
recommendations in ACI 201.2R-77.
StructuresMonitoring Program (B.1.27.2)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.5.2.2.2
 
under the heading, "Aging Management
 
of Inaccessible
 
Areas")Groups 1-5:
concrete (3.5.1-33)Reduction of strength and
 
modulus due to elevated temperature A plant-specificAMP is to be evaluatedNone(See SER Section 3.5.2.2.2
 
under the heading, "Reduction of
 
Strength and Modulus of Concrete Structures Due to Elevated Temperature")
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-402Group 6: Concrete; all (3.5.1-34)
Increase in porosityand permeability, cracking, loss of
 
material due to aggressive chemical attack; cracking, loss of bond, loss of
 
material due to
 
corrosion of
 
embedded steel Inspection ofWater-Control
 
Structures or FERC/US Army Corps of Engineers
 
dam inspections
 
and maintenance
 
programs and for
 
inaccessible
 
concrete, an examination of representative
 
samples of below-grade
 
concrete, and
 
periodic monitoring of groundwater, if the environment is non-aggressive. A
 
plant-specific
 
program is to be evaluated if environment is aggressive.
Buried Piping Inspection Program (B.1.1); Structures Monitoring Program (B.1.27.2)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.5.2.2.2
 
under the heading, "Aging Management
 
of Inaccessible Areas for Group 6
 
Structures," item 1)Group 6: exteriorabove and below
 
grade concrete
 
foundation
 
(3.5.1-35)
Loss of material (spalling, scaling)
 
and cracking due to freeze-thaw Inspection ofWater-Control
 
Structures or FERC/US Army Corps of Engineers
 
dam inspections
 
and maintenance
 
programs.
Evaluation is
 
needed for plants
 
that are located in moderate to severe weathering
 
conditions (weathering index
> 100 day-inch/yr)
(NUREG-1557).
StructuresMonitoring Program (B.1.27.2)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.5.2.2.2
 
under the heading, "Aging Management
 
of Inaccessible Areas for Group 6 Structures," item 2
)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-403Group 6: all accessible/
 
inaccessible
 
reinforced concrete
 
(3.5.1-36)Cracking due toexpansion/reaction with aggregates Accessible areas:
Inspection of Water-Control
 
Structures or FERC/US Army Corps of Engineers
 
dam inspections
 
and maintenance programs. None for
 
inaccessible areas if concrete was
 
constructed in accordance with the
 
recommendations in ACI 201.2R-77.Structures Monitoring Program (B.1.27.2)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Section 3.5.2.2.2
 
under the heading, "Aging Management of Inaccessible Areas for Group 6
 
Structures," item 3)Group 6: exteriorabove and below
 
grade reinforced
 
concrete foundation
 
interior slab
 
(3.5.1-37)
Increase in porosityand permeability, loss of strength due
 
to leaching of calcium hydroxideFor accessible areas, Inspection of Water-Control
 
Structures or FERC/US Army Corps of Engineers
 
dam inspections
 
and maintenance programs. None for
 
inaccessible areas if concrete was
 
constructed in accordance with the
 
recommendations in ACI 201.2R-77.Structures Monitoring Program (B.1.27.2)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Section 3.5.2.2.2
 
under the heading, "Aging Management of Inaccessible Areas for Group 6
 
Structures," item 3)Groups 7, 8: Tank liners (3.5.1-38)Cracking due toSCC; loss of
 
material due to pitting and crevice corrosion A plant-specificAMP is to be evaluatedNoneNot applicable. (See SER Section 3.5.2.2.2
 
under the heading, "Cracking Due to Stress Corrosion Cracking and Loss of Material Due to Pitting and Crevice Corrosion")
Support members;welds; bolted
 
connections;
 
support anchorage
 
to building structure
 
(3.5.1-39)
Loss of material due to general and
 
pitting corrosion StructuresMonitoring ProgramStructures Monitoring Program (B.1.27.2)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Section 3.5.2.2.2
 
under the heading, "Aging of Supports Not Covered by the Structures Monitoring
 
Program")
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-404 Building concrete at locations of expansion and
 
grouted anchors;
 
grout pads for
 
support base plates
 
(3.5.1-40)Reduction in concrete anchor capacity due to local
 
concrete degradation/
service-induced
 
cracking or other
 
concrete aging
 
mechanisms StructuresMonitoring ProgramStructures Monitoring Program (B.1.27.2)Consistent with theGALL Report, which
 
recommends further evaluation.
(See SER Section 3.5.2.2.2
 
under the heading, "Aging of Supports Not Covered by the Structures Monitoring
 
Program")Vibration isolation elements (3.5.1-41)Reduction or loss of isolation function/radiation
 
hardening, temperature, humidity, sustained vibratory loading StructuresMonitoring ProgramNoneNot applicable (See SER Section 3.5.2.2.2
 
under the heading, "Aging of Supports Not Covered by the Structures Monitoring
 
Program")Groups B1.1, B1.2, and B1.3: support
 
members: anchor bolts, welds
 
(3.5.1-42)Cumulative fatiguedamage (CLB fatigue analysis exists)TLAA, evaluated inaccordance with 10 CFR 54.21(c)NoneNot applicable. (See SER Section 3.5.2.2.2
 
under the heading, "Cumulative Fatigue Damage Due toCyclic Loading
")Groups 1-3, 5, 6: allmasonry block walls
 
(3.5.1-43)Cracking due to restraint shrinkage, creep, and aggressive environmentMasonry Wall ProgramMasonry Wall Program (B.1.27.1);
 
Fire Protection
 
Program (B.1.12.1)Consistent with theGALL Report.
(See SER Section 3.5.2.1.9)Group 6 elastomer seals, gaskets, and moisture barriers
 
(3.5.1-44)
Loss of sealing due to deterioration of
 
seals, gaskets, and moisture barriers (caulking, flashing, and other sealants)
StructuresMonitoring ProgramStructures Monitoring Program (B.1.27.2)Consistent with theGALL Report.
(See SER Section 3.5.2.1.10)Group 6: exteriorabove and below
 
grade concrete
 
foundation; interior
 
slab (3.5.1-45)
Loss of material due to abrasion, cavitation Inspection ofWater-Control
 
Structures Associated with Nuclear Power
 
PlantsNoneConsistent with theGALL Report.
(See SER Section 3.5.2.1.11)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-405Group 5: Fuel pool liners (3.5.1-46)Cracking due toSCC; loss of
 
material due to pitting and crevice corrosionWater Chemistry and monitoring of
 
spent fuel pool water level in accordance with
 
technical specifications and
 
leakage from the
 
leak chase
 
channels.Water ChemistryControl-BWR
 
Program (B.1.30.2)
 
and monitoring of spent fuel pool water level and level of fluid
 
in the leak chase
 
channelConsistent with theGALL Report.
(See SER Section 3.5.2.1)Group 6: all metal structural members
 
(3.5.1-47)
Loss of material due to general (steel only), pitting and crevice corrosion Inspection ofWater-Control
 
Structures or FERC/US Army Corps of Engineers
 
dam inspections
 
and maintenance. If protective coatings
 
are relied upon to
 
manage aging, protective coating
 
monitoring and
 
maintenance provisions should
 
be included.NoneConsistent withGALL Report, which
 
recommends no further evaluation (See SER Section 3.5.2.1.12)Group 6: earthenwater control
 
structures-dams, embankments, reservoirs, channels, canals, and ponds (3.5.1-48)
Loss of material, loss of form due to
 
erosion, settlement, sedimentation, frost action, waves, currents, surface
 
runoff, Seepage Inspection ofWater-Control
 
Structures Associated with Nuclear Power
 
PlantsNoneNot applicable.(VYNPS does not have earthen water control structures.)
Support members;welds; bolted
 
connections;
 
support anchorage
 
to building structure
 
(3.5.1-49)
Loss of material/general, pitting, and crevice corrosionWater Chemistryand ISI (IWF)Water ChemistryControl-BWR (B.1.30.2); Inservice
 
Inspection Program (B.1.15.2)Consistent with theGALL Report.
(See SER Section 3.5.2.1.13)Groups B2, and B4:galvanized steel, aluminum, stainless
 
steel support members; welds;
 
bolted connections;
 
support anchorage
 
to building structure
 
(3.5.1-50)
Loss of material due to pitting and crevice corrosion StructuresMonitoring ProgramStructures Monitoring Program (B.1.27.2)Consistent with theGALL Report.
(See SER Section 3.5.2.1.14)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-406Group B1.1: highstrength low-alloy
 
bolts (3.5.1-51)Cracking due toSCC; loss of
 
material due to
 
general corrosionBolting IntegrityNoneNot applicable.(High strength
 
bolting is not exposed to a corrosive environment or high tensile stresses.)Groups B2, and B4:
sliding support
 
bearings and sliding
 
support surfaces
 
(3.5.1-52)
Loss of mechanical function due to
 
corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic
 
thermal loads StructuresMonitoring ProgramNoneNot applicable. (Loss of mechanical
 
function due to the
 
listed mechanisms
 
is not an aging
 
effect. Such failures typically result from
 
inadequate design or operating events
 
rather than from the
 
effects of aging.
 
Failures due to cyclic thermal loads
 
are rare for
 
structural supports
 
due to their relatively low
 
temperatures.)Groups B1.1, B1.2, and B1.3: support members: welds;
 
bolted connections;
 
support anchorage
 
to building structure
 
(3.5.1-53)
Loss of material due to general and
 
pitting corrosionISI (IWF)Inservice Inspection Program (B.1.15.2)Consistent with theGALL Report.
(See SER Section 3.5.2.1.15)Groups B1.1, B1.2,and B1.3: Constant and variable load
 
spring hangers;
 
guides; stops;
 
(3.5.1-54)
Loss of mechanical function due to
 
corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic
 
thermal loadsISI (IWF)NoneNot applicable.(Loss of mechanical
 
function due to
 
distortion, dirt, overload, fatigue due to vibratory, and cyclic thermal loads
 
are not aging effects
 
requiring management. Such failures typically
 
result from
 
inadequate design or events rather
 
than the effects of
 
aging.)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-407Steel, galvanized steel, and aluminum
 
support members; welds; bolted
 
connections;
 
support anchorage
 
to building structure
 
(3.5.1-55)
Loss of material due to boric acid corrosionBoric AcidCorrosionNoneNot applicable toBWRsGroups B1.1, B1.2, and B1.3: Sliding
 
surfaces (3.5.1-56)
Loss of mechanical function due to
 
corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic
 
thermal loadsISI (IWF)Inservice Inspection Program (B.1.15.2);
Structures Monitoring
 
Program (B.1.27.2)Not applicable.(No aging effects due
 
to lubrite plate design features. VYNPS will
 
manage aging anyway.)Groups B1.1, B1.2, and B1.3: Vibration
 
isolation elements
 
(3.5.1-57)Reduction or loss of isolation function/
 
radiation hardening, temperature, humidity, sustained vibratory loadingISI (IWF)NoneNot applicable.(No supports with vibration isolation
 
elements are
 
in-scope.)Galvanized steel and aluminum
 
support members; welds; bolted
 
connections;
 
support anchorage
 
to building structure exposed to
 
air-indoor
 
uncontrolled
 
(3.5.1-58)NoneNoneNoneConsistent with theGALL Report.
(See SER Section 3.5.2.1.16)
Stainless steel support members; welds; bolted
 
connections;
 
support anchorage
 
to building structure
 
(3.5.1-59)NoneNoneNoneConsistent with theGALL Report.
(See SER Section 3.5.2.1)The staff's review of the SC supports component groups followed any one of severalapproaches. One approach, documented in SER Section 3.5.2.1, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.5.2.2, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.5.2.3, reviewed AMR results for components that the applicant indicated are not consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the SC supports components is documented in SER Section 3.0.3.
3-4083.5.2.1  AMR Results Consistent with the GALL ReportSummary of Technical Information in the Application. LRA Section 3.5.2.1 identifies thematerials, environments, AERMs, and the following programs that manage aging effects for the SC supports components:
* Containment Leak Rate Program
* Fire Protection Program
* Containment Inservice Inspection Program
* Inservice Inspection Program
* Periodic Surveillance and Preventive Maintenance Program
* Masonry Wall Program
* Structures Monitoring Program
* Vernon Dam Federal Energy Regulatory Commission Inspection
* Water Chemistry Control - BWR ProgramLRA Tables 3.5.2-1 through 3.5.2-6 summarize AMRs for the SC supports components andindicate AMRs claimed to be consistent with the GALL Report.Staff Evaluation. For component groups evaluated in the GALL Report for which the applicantclaimed consistency with the report and for which it does not recommend further evaluation, the staff's audit and review determined whether the plant-specific components of these GALL Report component groups were bounded by the GALL Report evaluation.The applicant noted for each AMR line item how the information in the tables aligns with theinformation in the GALL Report. The staff audited those AMRs with notes A through E indicating how the AMR is consistent with the GALL Report.Note A indicates that the AMR line item is consistent with the GALL Report for component,material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP.
The staff audited these line items to verify consistency with the GALL Report and validity of the AMR for the site-specific conditions.Note B indicates that the AMR line item is consistent with the GALL Report for component,material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify consistency with the GALL Report and verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also finds whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions.Note C indicates that the component for the AMR line item, although different from, is consistentwith the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing 3-409of some system components in the GALL Report; however, the applicant identified in the GALLReport a different component with the same material, environment, aging effect, and AMP as the component under review. The staff audited these line items to verify consistency with the GALL Report. The staff also finds whether the AMR line item of the different component was applicable to the component under review and whether the AMR was valid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different from, is consistentwith the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component was applicable to the component under review and whether the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also finds whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions.Note E indicates that the AMR line item is consistent with the GALL Report for material,environment, and aging effect, but credits a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also finds whether the credited AMP would manage the aging effect consistently with the GALL AMP and whether the AMR was valid for the site-specific conditions.The staff audited and reviewed the information in the LRA. The staff did not repeat its review ofthe matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluation follows.3.5.2.1.1  Loss of Material Due to General, Pitting and Crevice Corrosion For loss of material due to general, pitting and crevice corrosion of carbon steel for drywell,torus, drywell head, embedded shell and sand pocket regions, drywell support skirt, torus ring girder, downcomers, liner plate, ECCS suction header, support skirt, region shielded by diaphragm floor and suppression chamber exposed to indoor uncontrolled air or treated water, the GALL Report recommends programs consistent with GALL AMP XI.S1, "ASME Section XI, Subsection IWE" and GALL AMP XI.S4, "10 CFR Part 50, Appendix J."In LRA Table 3.5.1, Item 3.5.1-5, the applicant stated that loss of material due to general, pittingand crevice corrosion of the carbon steel drywell head, drywell shell, drywell sump liner, drywell to torus vent system, torus manway, torus ring girder, torus shell, and torus thermowell is managed using its Containment Inservice Inspection Program and the Containment Leak Rate Program.During the audit and review, the staff noted that the applicant's Containment Inservice InspectionProgram is a plant-specific program.
3-410The staff reviewed the applicant's Containment Inservice Inspection Program. This evaluation isdocumented in SER Section 3.0.3.3.2. The staff finds that the applicant's Containment Inservice Inspection Program satisfied criteria of SRP-LR Appendix A.1 and encompasses the ASME Code, Section XI, Subsection IWE requirements for managing the loss of material for the primary containment and its integral attachments. On this basis, the staff concludes that the applicant's Containment Inservice Inspection Program is an acceptable AMP for loss of material of the above components.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.5.2.1.2  Cumulative Fatigue Damage (CLB Fatigue Analysis Exists)
During the audit and review, the staff noted that in LRA Table 3.5.2-1 (page 3.5-53) for thecomponent torus shell with the aging effect of cracking fatigue, the note assigned is E. Note E is consistent with the GALL Report material, environment, and aging effect but a different AMP is credited. The applicant was asked to explain why this note is E when the AMP shown for this line item is TLAA and the referenced GALL Report Line Item II.B1.1-4 also specifies a TLAA.In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRATable 3.5.2-1 is revised to change Note E to Note A for torus shell with an aging effect of cracking-fatigue. The aging effect and associated AMP are unchanged.The staff reviewed the applicant's response and finds it acceptable. On the basis of its review,the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.5.2.1.3  Cracking Due to Cyclic Loading For cracking due to cyclic loading of steel, stainless steel and dissimilar metal welds forpenetration sleeves, penetration bellows, suppression pool shell and unbraced downcomers exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S1, "ASME Code, Section XI, Subsection IWE" and GALL AMP XI.S4, "10 CFR Part 50, Appendix J."In LRA Table 3.5.1, Item 3.5.1-12, the applicant stated that cracking due to cyclic loading of thecarbon steel primary containment mechanical penetrations (includes those with bellows) is managed using the Containment Inservice Inspection Program and the Containment Leak Rate Program.During the audit and review, the staff noted that the applicant's Containment Inservice InspectionProgram is a plant-specific program.
3-411The staff reviewed the applicant's Containment Inservice Inspection Program and its evaluationis documented in SER Section 3.0.3.3.2. The staff finds that the applicant's Containment Inservice Inspection Program satisfied criteria of SRP-LR Appendix A.1 and encompasses the ASME Code, Section XI Subsection IWE Code requirements for managing cracking of the primary containment and its integral attachments. On this basis, the staff concludes that the applicant's Containment Inservice Inspection Program is an acceptable AMP for managing cracking of the primary containment mechanical penetrations (includes those with bellows).For cracking due to cyclic loading of steel, stainless steel and dissimilar metal welds for torus,vent line, vent header, vent line bellows and downcomers exposed to indoor uncontrolled air, the GALL Report recommends programs consistent with GALL AMP XI.S1, "ASME Code, Section XI, Subsection IWE" and GALL AMP XI.S4, "10 CFR Part 50, Appendix J."In LRA Table 3.5.1, Item 3.5.1-13, the applicant stated that cracking due to cyclic loading of thestainless steel drywell to torus vent line bellows is managed using the Containment Inservice Inspection Program and the Containment Leak Rate Program.During the audit and review, the staff noted that the applicant's Containment Inservice InspectionProgram is a plant-specific program. The staff reviewed the applicant's Containment Inservice Inspection Program and its evaluationis documented in SER Section 3.0.3.3.2. The staff finds that the applicant's containment Inservice Inspection Program satisfied criteria of SRP-LR Appendix A.1 and encompasses the ASME Code, Section XI Subsection IWE Code requirements for managing cracking of the primary containment and its integral attachments. On this basis, the staff concludes that the applicant's plant-specific Containment Inservice Inspection Program is an acceptable AMP formanaging cracking of the drywell to torus vent line bellows.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.During the audit and review, the staff noted that in LRA Table 3.5.2-1 (page 3.5-50), forcomponent bellows (reactor vessel and drywell), one of the AMPs shown is the Containment Inservice Inspection-IWE Program, which is a plant-specific AMP. A Note C has been assigned to this AMR line item, the component is different, but consistent with material, environment, aging effect, and AMP for the GALL Report line item. The AMP is consistent with the GALL Report's AMP description. The applicant was asked to provide drawings showing how the LRA line item bellows are different from the GALL Report Table 1, Line Item 3.5.1-13 bellows. The applicant was also asked to explain how the plant-specific VYNPS Containment Inservice Inspection-IWE AMP is consistent with the GALL Report's specified AMP.The applicant's staff stated that LRA Table 3.5.2-1 (page 3.5-50), for component bellows(reactor vessel and drywell) is not consistent with the referenced GALL Report Volume 2 item.
LRA Table 3.5.2-1 line item "Bellows (reactor vessel and drywell)" and the corresponding line item in VYNPS Table 2.4-1 should be deleted. The reactor vessel and drywell bellows perform 3-412no license renewal intended function. These components are not safety-related and are notrequired to demonstrate compliance with the requirements of 10 CFR 54.4(a)(3). Failure of the bellows will not prevent satisfactory accomplishment of a safety function. Leakage, if any, through the bellows is directed to a drain system that prevents the leakage from contacting the outer surface of the drywell shell.In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRATable 3.5.2-1 is revised to delete line items for "Bellows (reactor vessel and drywell)" and also the corresponding line item in LRA Table 2.4-1. The staff reviewed the applicant's response and finds it acceptable. On the basis of its review,the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.5.2.1.4  Loss of Sealing and Leakage Through Containment Due to Deterioration of JointSeals, Gaskets, and Moisture Barriers (Caulking, Flashing, and Other Sealants)During the audit and review, the staff noted that in the discussion column of LRA Table 3.5.1,Item 3.5.1-16, the applicant stated that seals and gaskets are not included in the Containment Inservice Inspection Program at VYNPS. One of the components for this item number is moisture barriers. The applicant was asked to explain how VYNPS seals the joint between the containment drywell shell and drywell concrete floor if there is no moisture barrier. The applicant was also asked to explain why the inspection of this joint is not part of the Containment Inservice Inspection Program at VYNPS.The applicant's staff stated that VYNPS uses a moisture barrier to seal the joint between thecontainment drywell shell and drywell concrete floor. Moisture barrier is listed in LRA Table 3.5.2-1 as drywell floor liner seal. Aging effects on the drywell moisture barrier will be managed by its Containment Inservice Inspection-IWE Program. For clarity, drywell floor liner seal will be changed to drywell shell to floor seal (moisture barrier).During the audit and review, the staff noted that in LRA Table 3.5.2-1 (page 3.5-54) for thecomponent drywell floor liner seal, the AMP shown is the Structures Monitoring Program. The applicant was asked to verify that its Containment Inservice Inspection-IWE AMP will not be used instead to manage the aging of the moisture barrier.The applicant's staff stated that the aging management activity will be the same whetherincluded in accordance with the umbrella of the Structures Monitoring Program or in accordance with the umbrella of the Containment Inservice Inspection-IWE Program. For clarification, the Containment Inservice Inspection-IWE Program will manage the effects of aging on the moisture barrier through the period of extended operation. Note E remains the correct note since the Containment Inservice Inspection-IWE Program is plant-specific.
3-413In a letter dated July 14, 2006, the applicant revised its LRA. Specifically, the applicant statedthat aging effects on the drywell moisture barrier will be managed in accordance with the Containment Inservice Inspection Program instead of the Structures Monitoring Program. In support of this, the LRA is revised as follows:  (1)In the LRA Table 3.5.2-1 line item for "Drywell floor liner seal" change the agingmanagement program from "Structures Monitoring" to "CII-IWE." For clarification, change "drywell floor liner seal" to "drywell shell to floor seal (moisture barrier)." The clarification of this terminology also applies to LRA Table 2.4-1 and Section B.1.27.2.  (2)In LRA Table 3.5.1, Line Item 3.5.1-16, the Discussion column is revised to read: "Theaging effects cited in the GALL Report item are loss of sealing and leakage. Loss of sealing is a consequence of the aging effects "cracking" and "change in material properties." For VYNPS, the Containment Leak Rate Program manages cracking and changes in material properties for the primary containment seal and gaskets. The Inservice Inspection-IWE Program manages cracking and changes in material properties for the drywell shell to floor seal (moisture barrier)."  (3)In LRA Table 3.5.1, Line Item 3.5.1-5, the Discussion column last paragraph is revised toread "The drywell steel shell and the moisture barrier where the drywell shell becomes embedded in the drywell concrete floor are inspected in accordance with the Containment Inservice Inspection (IWE) Program."  (4)LRA Section 3.5.2.2.1.4 is revised to delete from the end of the first paragraph, thephrase "and Structures Monitoring Program." The drywell to floor moisture barrier will be inspected in accordance with the Containment Inservice Inspection (IWE) Program only.
The Structures Monitoring Program is not used.The staff reviewed the applicant's response and finds it acceptable. On the basis of its review,the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.During the audit and review, the staff noted that in the applicant response above, the applicantstated:In LRA Table 3.5.1, Line Item 3.5.1-16, the Discussion column is revised to read:"The aging effects cited in the GALL Report item are loss of sealing and leakage.
Loss of sealing is a consequence of the aging effects "cracking" and "change in material properties." For VYNPS, the Containment Leak Rate Program manages cracking and changes in material properties for the primary containment seal and gaskets. The Inservice Inspection-IWE Program manages cracking and changes in material properties for the drywell shell to floor seal (moisture barrier)."The staff noted that in LRA Table 3.5.2-6 (page 3.5-80), for component seals and gaskets(doors, man-ways and hatches), material rubber in a protected from weather environment; the aging effects are cracking and change in material properties. The GALL Report line item referenced is II.B4-7 and the LRA Table 1 reference is Line Item 3.5.1-16. However, theAMP shown for this line item is Periodic Surveillance and Preventive Maintenance Program. LRA 3-414Table 3.5.1, Item 3.5.1-16 relates to primary containment seals and gaskets. The applicant hasstated above in the previous paragraph that the Containment Leak Rate Program manages cracking and change in material properties for the primary containment seals and gaskets. The applicant was asked to explain if this Table 2 line item is for containment seals and gaskets and also Class 1 structures seals and gaskets. If it is for both containment seals and gaskets and Class 1 structures seals and gaskets, the applicant was asked to explain why the line is not broken into two AMPs, two GALL items, two Table 1 items and two notes. The AMP for the containment seals and gaskets would be Containment Leak Rate Program with the GALL Report Item II.B4-7, the LRA Table 1 Line Item 3.5.1-16 and a note A. The AMP for the Class 1structures seals and gaskets would probably be the Periodic Surveillance and Preventive Maintenance Program.The applicant's staff stated that LRA Table 3.5.2-6 line item "Seals and gaskets-" onpage 3.5-80 is for Class 1 structure seals and gaskets not associated with primary containment boundary. Containment seals and gaskets are addressed in LRA Table 3.5.2-1 line item "Primary containment electrical penetration-" on page 3.5-55. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.1, Item 3.5.1-16 discussion is revised to add the following paragraph:"For reactor building seals and gaskets, the Periodic Surveillance and PreventiveMaintenance Program manages cracking and change in material properties for the railroad inner and outer lock doors elastomer seals."The staff finds that since the GALL does not have similar line item to LRA Table 3.5.1 line itemfor Class 1 structures seals and gaskets other than for Group 6, the applicant has chosen to align the component Class 1 structures seals and gaskets with GALL Report Table 3.5.1, Line Item 3.5.1-16, which is for the primary containment seals and gaskets. The staff's evaluation of the use of the Periodic Surveillance and Preventive Maintenance Program to manage cracking and change in material properties for the railroad inner and outer lock doors elastomer seals is therefore provided in SER Section 3.5.2.3.8, "Bulk Commodities-Summary of Aging Management Evaluation."For loss of sealing and leakage through containment due to deterioration of elastomer, rubberand other similar material joint seals, gaskets, and moisture barriers (caulking, flashing, and other sealants) exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S1, "ASME Code, Section XI, Subsection IWE" and GALL AMP XI.S4, "10 CFR Part 50, Appendix J."The staff noted that the applicant manages cracking and change in material properties due todeterioration of the elastomer drywell shell to floor seal (moisture barrier) exposed to a protected from weather environment using the Containment Inservice Inspection Program (plant-specific) only. The moisture barrier is a containment internal seal and therefore the requirement of 10 CFR 50, Appendix J, does not apply.
3-415The staff reviewed the applicant's Containment Inservice Inspection Program and its evaluationis documented in SER Section 3.0.3.3.2. The Containment Inservice Inspection Program encompasses the ASME Code, Section XI Subsection IWE Code requirements for managing the deterioration (cracking and change in material properties) of the primary containment moisture barrier through visual inspections.Because the applicant's plant-specific Containment Inservice Inspection Program includes thesame requirements for inspection and detection of deterioration of the VYNPS primary containment moisture barrier through visual inspections as the ASME Code, Section XI Subsection IWE Code, the staff finds it to be an acceptable management program for detecting cracking and change in material properties.For loss of sealing and leakage through containment due to deterioration of elastomer, rubberand other similar material joint seals, gaskets, and moisture barriers (caulking, flashing, and other sealants) exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S1, "ASME Code, Section XI, Subsection IWE" and GALL AMP XI.S4, "10 CFR Part 50, Appendix J."The staff noted that for cracking and change in material properties due to deterioration of theelastomer primary containment electrical penetration seals and sealant exposed to a protected from weather environment (LRA page 3.5-55) is managed using only the Containment Leak Rate Program instead of both GALL AMP, GALL AMP XI.S1 and GALL AMP XI.S4.The staff reviewed the applicant's Containment Leak Rate Program. This evaluation isdocumented in SER Section 3.0.3.2.8. The Containment Leak Rate Program is the only AMP needed to detect deterioration of the containment electrical penetration seals and sealant.
Although the GALL Report specifies GALL AMP XI.S1, "ASME Code, Section XI, Subsection IWE" also for this material, environment and aging effect, the 1998 Edition and later editions of ASME Code, Section XI, Subsection IWE do not require the inspection of seals and gaskets. Since the applicant has not assigned two AMPs to manage this aging effect, the applicant has conservatively called the application of only the Containment Leak Rate Program a different program with respect to the GALL Report.On the basis of its review, the staff finds that the applicant's Containment Leak Rate Program isconsistent with the GALL Report (with exceptions) and the 1998 Edition and later editions of the ASME Code, Section XI, Subsection IWE, do not require the inspection of seals and gaskets.
The staff concludes that the applicant's Containment Leak Rate Program alone to be an acceptable management program for detecting cracking and change in material properties of containment electrical penetration seals and sealants.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
3-4163.5.2.1.5  Loss of Leak Tightness in Closed Position Due to Mechanical Wear of Locks, Hingesand Closure MechanismsIn the LRA Table 3.5.1, Item 3.5.1-17, the applicant stated that locks, hinges, and closuremechanisms are active components and are therefore not subject to an AMR. During the audit and review, the applicant was asked to provide any license renewal regulatory guidance document or previous NRC SER that has ever stated that locks, hinges, and closure mechanisms are active components. If locks, hinges, and closure mechanisms are active components at VYNPS, the applicant was asked to provide an itemized list of these active components with their qualified life or specified time period of replacement. The applicant was also asked to explain how VYNPS tracks the active life of these components before replacement.The applicant's staff stated that it may be a misnomer to refer to these components as activecomponents since the requirement of 10 CFR 54.21(a)(1)(i) does not refer to active or passive components, but rather excludes from an AMR, components with moving parts or with a change in configuration or properties that perform an intended function in accordance with 10 CFR 54.4.
Locks, hinges, and closure mechanisms perform their functions with moving parts. This exception is not based on a qualified life or specified time period of replacement for a component. 10 CFR 54.21(a)(1)(ii) requirements provide a separate exclusion for components that are replaced based on a qualified life. Other precedents for locks, hinges, and closure mechanisms as active components that have received approval by the NRC are found in Peach Bottom (NUREG-1769, Section 3.0.3.14.2, page 3-58) and Millstone (NUREG-1838, Section 3.3A.2.1.4, page 3-245).The staff reviewed the Peach Bottom and Millstone SERs which verify that locks, hinges, andother closure mechanisms have been accepted as active components and are excluded from an AMR. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.5.2.1.6  Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting and crevice corrosion of steel (and dissimilar metalwelds) penetration sleeves, personnel airlock, equipment hatch and CRD hatch exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S1, "ASME Code, Section XI, Subsection IWE" and GALL AMP XI.S4, "10 CFR Part 50, Appendix J."The staff noted that loss of material of the carbon steel CRD removal hatch, equipment hatch,personnel airlock, primary containment electrical penetrations, torus electrical penetrations, and torus mechanical penetrations exposed to a protected from weather environment (LRA pages 3.5-50 and 51) is managed using its Containment Inservice Inspection Program, which is a plant-specific AMP, and the Containment Leak Rate Program.
3-417The staff reviewed the applicant's Containment Inservice Inspection Program and its evaluationis documented in SER Section 3.0.3.3.2. The staff finds that the applicant's containment Inservice Inspection Program satisfied criteria of SRP-LR Appendix A.1 and encompasses the ASME Code, Section XI Subsection IWE requirements for managing loss of material for primary containment and its integral attachments. On this basis, the staff concludes that the applicant's plant-specific Containment InserviceInspection Program is an acceptable management program for managing loss of material of the above components. The staff finds the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.5.2.1.7  Fretting or Lock Up Due to Mechanical Wear In LRA Table 3.5.1, Item 3.5.1-21, the applicant stated that VYNPS plant operating experiencehas not identified fretting or lock up due to mechanical wear for the drywell head and downcomers. During the audit and review, the staff noted that plant operating experience does not find fretting or lock up due to mechanical wear but inspections do. The applicant was asked to explain if VYNPS staff currently inspect for wear of the drywell head and downcomer pipes in accordance with the CLB using the Containment Inservice Inspection Program. If VYNPS currently does inspect these components for wear, justify the basis for not performing these same inspections during an extended license period. If required, provide drawings showing the spacial distance between components such that fretting cannot occur.The applicant's staff stated condition reports are a primary source of operating experiencedocumentation reviewed for license renewal. Condition reports document negative inspection results. The GALL Report defines neither fretting nor lockup and further confuses the subject by stating that fretting and lockup are caused by mechanical wear which is an aging mechanism resulting in the aging effect loss of material. The definition in GALL AMP IX.E merely states that fretting and lockup is an aging effect along with a cause, but doesn't say what it is or what it looks like. As indicated in the line item for drywell head in LRA Table 3.5.2-1, the Containment Inservice Inspection-IWE Program and the Containment Leak Rate Program manage loss of material. Loss of material is the aging effect caused by mechanical wear. VYNPS inspects the drywell head and downcomers (torus vent system) per the requirements of ASME Code, Section XI. In addition, the drywell head and downcomers are stationary, well-braced components and the spacial distance between connecting components make it unlikely for fretting and lockup to occur.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.5.2.1.8  Loss of Material Due to General and Pitting Corrosion For loss of material due to general, pitting and crevice corrosion of steel support members,welds, bolted connections; and support anchorage to building structure exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S6, "Structures Monitoring Program."
3-418During the audit and review, the staff noted that loss of material of carbon steel damper framingexposed to a protected from weather environment is managed using the Fire Protection Program (with exceptions to the GALL Report and enhancements).The staff reviewed the applicant's Fire Protection Program and its evaluation is documented inSER Section 3.0.3.2.11. The Fire Protection Program will be enhanced in accordance with the parameters monitored/inspected element to specify that fire damper frames in fire barriers shall be inspected for corrosion (loss of material). This requirement will also be added to field procedures. In a letter dated July 6, 2006, the applicant revised its LRA. The applicant revised the VYNPSLicense Renewal Commitments List to state that procedures will be enhanced to specify that fire damper frames in fire barriers will be inspected for corrosion. Acceptance criteria will be enhanced to verify no significant corrosion. The implementation schedule is before March 21, 2012.On the basis that the applicant's Fire Protection Program will be enhanced to include inaccordance with parameters monitored/inspected that fire damper frames in fire barriers be inspected for corrosion (loss of material), the staff finds that it is an acceptable management program for managing loss of material of the damper framing in lieu of the recommended GALL AMP XI.S6.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.For loss of material due to general, pitting and crevice corrosion of steel support members,welds, bolted connections; and support anchorage to building structure exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S6, "Structures Monitoring Program."During the audit and review, the staff noted that loss of material of carbon steel fire hose reelsexposed to a protected from weather environment is managed using the Fire Water System Program (with exceptions to the GALL Report and enhancements).The staff reviewed the applicant's Fire Water System Program evaluation is documented in SERSection 3.0.3.2.12. The Fire Water System Program applies to water-based fire protection systems that consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations (including Fire hose reels), standpipes, and aboveground and underground piping and components.
Components are tested in accordance with applicable NFPA codes and standards. Such testing assures that carbon steel Fire hose reels will be inspected for corrosion (loss of material).On the basis that the applicant's Fire Water System Program includes hose stations (includingfire hose reels) which are tested in accordance with NFPA codes and standards which will detect corrosion, the staff finds that it is an acceptable AMP for managing loss of material of fire hose reels in lieu of the recommended GALL AMP XI.S6.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
3-4193.5.2.1.9  Cracking Due to Restraint Shrinkage, Creep, and Aggressive EnvironmentFor cracking due to restraint shrinkage, creep and aggressive environment of concrete blockmasonry walls exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S5, "Masonry Wall Program."In LRA Table 3.5.2-5 (page 3.5-67), the applicant stated that cracking of concrete brick forVernon Dam masonry walls exposed to a weather environment is managed using the Vernon Dam FERC Inspection Program. During the audit and review, the staff finds that inspections of the Vernon Dam are not part of aVYNPS AMP but inspections are conducted by the owner of the dam in accordance with FERC oversight. Vernon dam personnel conduct a daily visual inspection of all the project facilities. An operations crew attends the plant daily. Vernon dam engineering performs an annual inspection of all the project structures and divers make a thorough inspection once every five year on both upstream and downstream sides. The operational inspection frequency for licensed and exempt low hazard potential dams is biennial. Reports of operational inspections are filed with the FERC. The staff has finds that mandated FERC inspection programs are acceptable for aging management.On the basis that the inspection and maintenance of the Vernon Dam is in accordance with theregulatory jurisdiction and are conducted by FERC or the US Army Corp of Engineers, the staff finds the aging management of the dam is adequate. The staff's evaluation of the Vernon Dam FERC Inspection Program is documented in SER Section 3.0.3.3.6. The staff finds that FERC Inspection will adequately manage the aging effects for the Vernon Dam and that the management of cracking of concrete brick for Vernon Dam masonry walls exposed to a weather environment is acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.5.2.1.10  Loss of Sealing Due to Deterioration of Seals, Gaskets, and Moisture Barriers(Caulking, Flashing, and Other Sealants)During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-80), forcomponent seals and gaskets (doors, manways and hatches), material rubber in a protected from weather environment; the aging effects are cracking and change in material properties.
One of the AMP s shown is the Structures Monitoring Program. The GALL Report line item referenced is III.A6-12 and the LRA Table 1 reference is Line Item 3.5.1-44. The note shown isE, different AMP than shown in the GALL Report. However, the GALL Report Line Item III.A6-12and LRA Table 1 Line Item 3.5.1-44 both specify the Structures Monitoring Program. The applicant was asked to explain why the note shown is not A instead of E for the lower half of this AMR line item.During the audit and review, the applicant's staff stated that LRA Table 3.5.2-6 (page 3.5-80), forcomponent seals and gaskets (doors, manways and hatches), material rubber in a protected from weather environment; the aging effects are cracking and change in material properties. The LRA will be clarified to indicate that note "A" applies to the line for SMP.
3-420In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRATable 3.5.2-6 is revised to indicate that note A applies to component seals and gaskets (doors, man-ways and hatches) with the Structures Monitoring Program.The staff reviewed the applicant's response and finds it acceptable. On the basis of its review,the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.3.5.2.1.11  Loss of Material Due to Abrasion, Cavitation For loss of material due to abrasion and cavitation of reinforced concrete exterior above andbelow grade foundation and interior slab exposed to flowing water, the GALL Report recommends programs consistent with GALL AMP XI.S7, "Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants."During the audit and review, the staff noted that loss of material of reinforced concrete exteriorwalls below grade (SW area), exterior walls below grade (CWS area), foundation, interior walls below grade, exterior walls above grade, exterior walls below grade and foundation (cooling tower) exposed to a fluid environment is managed using the Structures Monitoring Program (with enhancements) instead of the recommended GALL AMP XI.S7.The staff reviewed the applicant's Structures Monitoring Program and its evaluation isdocumented in SER Section 3.0.3.2.17. VYNPS is not committed to RG 1.127. GALL AMP XI.S7 states that for plants not committed to RG 1.127, Revision 1, aging management of water-control structures may be included in the Structures Monitoring Program. The program elements of GALL AMP XI.S7 applicable to the water control structures at VYNPS have been incorporated into the VYNPS Structures Monitoring Program.On the basis that the applicant's Structures Monitoring Program includes the program elementsof GALL AMP XI.S7 applicable to the water control structures at VYNPS as recommended by the GALL Report, the staff finds it to be an acceptable AMP for loss of material of the components listed above.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.In LRA Table 3.5.2-5 (page 3.5-67), the applicant stated that loss of material of concrete for theVernon Dam external walls above/below grade exposed to fluid environment is managed by its Vernon Dam FERC Inspection Program. The referenced GALL Report line item is III.A6-7. The GALL Report Line Item III.A6-7 states thefollowing in accordance with AMP: Chapter XI.S7, "Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. Since one of the AMPs in accordance with this GALL Report line item is FERC dam inspections, the applicant was asked to explain why the note assigned to the LRA AMR line item is E instead of A, where note A is consistent with the GALL Report.
3-421During the audit and review, the staff finds that inspections of the Vernon Dam are not part of aVYNPS AMP but inspections are conducted by the owner of the dam in accordance with FERC oversight. Vernon dam personnel conduct a daily visual inspection of all the project facilities. An operations crew attends the plant daily. Vernon dam engineering performs an annual inspection of all the project structures and divers make a thorough inspection once every five year on both upstream and downstream sides. The operational inspection frequency for licensed and exempt low hazard potential dams is biennial. Reports of operational inspections are filed with the FERC. The staff has finds that mandated FERC inspection programs are acceptable for aging management.On the basis that the inspection and maintenance of the Vernon Dam is in accordance with theregulatory jurisdiction and are conducted by FERC or the US Army Corp of Engineers, the staff finds the aging management of the dam is adequate. The staff's evaluation of the Vernon Dam FERC Inspection Program is documented in SER Section 3.0.3.3.6. The staff finds that FERC Inspection will adequately manage the aging effects for the Vernon Dam and that the loss of material of concrete for the Vernon Dam external walls above/below grade exposed to fluid environment is acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.5.2.1.12  Loss of Material Due to General (Steel Only), Pitting and Crevice Corrosion For loss of material due to general, pitting and crevice corrosion of group six metal structuralmembers exposed to indoor uncontrolled air, outdoor air, flowing water, or standing water the GALL Report recommends programs consistent with GALL AMP XI.S7, "Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants."During the audit and review, the staff noted that loss of material of metal Structural steel: beams,columns, plates exposed to a protected from weather or fluid environment; metal anchorage/embedments exposed to a fluid environment; metal manway hatches and hatch covers exposed to a protected from weather or weather environment; and structural bolting exposed to a fluid environment is managed using the Structures Monitoring Program (with enhancements) instead of the recommended GALL AMP XI.S7.The staff reviewed the applicant's Structures Monitoring Program and its evaluation isdocumented in SER Section 3.0.3.2.17. VYNPS is not committed to RG 1.127. GALL AMP XI.S7 states that for plants not committed to RG 1.127, Revision 1, aging management of water-control structures may be included in the Structures Monitoring Program. The program elements of GALL AMP XI.S7 applicable to the water control structures at VYNPS have been incorporated into the VYNPS Structures Monitoring Program.On the basis that the applicant's Structures Monitoring Program includes the program elementsof GALL AMP XI.S7 applicable to the water control structures at VYNPS as recommended by the GALL Report, the staff finds it is an acceptable management program for managing loss of material of the components listed above.
3-422On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.In LRA Table 3.5.2-5 (page 3.5-66), the applicant stated that loss of material of carbon steel forthe Vernon Dam structural steel protected from weather or exposed to weather or fluid environments is managed by Vernon Dam FERC Inspection Program.The referenced GALL Report line item for all three environments is III.A6-11. The GALL ReportLine Item III.A6-11 states the following in accordance with AMP: Chapter XI.S7, "RegulatoryGuide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. Since one of the AMPs in accordance with this GALL Report line item is FERC dam inspections, the applicant was asked to explain why the note assigned to the three LRA AMR line items is E instead of A, where note A is consistent with the GALL Report.During the audit and review, the staff finds that inspections of the Vernon Dam are not part of aVYNPS AMP but inspections are conducted by the owner of the dam in accordance with FERC oversight. Vernon dam personnel conduct a daily visual inspection of all the project facilities. An operations crew attends the plant daily. Vernon dam engineering performs an annual inspection of all the project structures and divers make a thorough inspection once every five year on both upstream and downstream sides. The operational inspection frequency for licensed and exempt low hazard potential dams is biennial. Reports of operational inspections are filed with the FERC. The staff has finds that mandated FERC inspection programs are acceptable for aging management.On the basis that the inspection and maintenance of the Vernon Dam is in accordance with theregulatory jurisdiction and are conducted by FERC or the US Army Corp of Engineers, the staff finds the aging management of the dam is adequate. The staff's evaluation of the Vernon Dam FERC Inspection Program is documented in SER Section 3.0.3.3.6. The staff finds that FERC Inspection will adequately manage the aging effects for the Vernon Dam and that loss of material of carbon steel for the Vernon Dam structural steel protected from weather or exposed to weather or fluid environments is acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.5.2.1.13  Loss of Material/General, Pitting and Crevice Corrosion For loss of material due to general, pitting and crevice corrosion of stainless steel and steelsupport members; bolted connections; support anchorage to building structure exposed to treated water (less than140F) the GALL Report recommends programs consistent with GALLAMP XI.M2, "Water Chemistry," for BWR water, and GALL AMP XI.S3, "ASME Code, Section XI, Subsection IWF."During the audit and review, the staff noted that loss of material of carbon steel and stainlesssteel anchorage/embedments exposed to a fluid environment is managed using the Water Chemistry Control-BWR Program and the Inservice Inspection Program, which is a plant-specific AMP instead of the GALL AMP XI.S3.
3-423The staff reviewed the applicant's Inservice Inspection Program and its evaluation isdocumented in SER Section 3.0.3.3.3. The applicant's Inservice Inspection Program encompasses the ASME Code, Section XI Subsection IWF requirements for managing the loss of material for ASME Code Class 1, 2, and 3 steel piping supports and steel component supports within containment.On the basis that the applicant's plant-specific Inservice Inspection Program includes the samerequirements for inspection and detection of loss of material for ASME Code Class 1, 2, and 3 steel piping supports and steel component supports within containment as the ASME Code, Section XI Subsection IWF, the staff finds it to be an acceptable management program for loss of material of carbon steel and stainless steel anchorage/embedments.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.5.2.1.14  Loss of Material Due to Pitting and Crevice Corrosion In LRA Table 3.5.1, Item 3.5.1-50, the applicant stated that loss of material due to pitting andcrevice corrosion of Groups B2 and B4 galvanized steel, aluminum, and stainless steelcomponents in an outdoor air environment is not applicable at VYNPS. During the audit and review, the staff noted that NUREG-1833, "Technical Bases for Revision to the License Renewal Guidance Documents," on page 93 for Item TP-6 states: An approved precedent exists for adding this material, environment, aging effect,and program combination to the GALL Report. As shown in RNP [Robinson Nuclear Plant] SER Section 3.5.2.4.3.2, galvanized steel and stainless steel in anoutdoor air environment could result in loss of material due to constant wetting and drying conditions. Aluminum would also be susceptible to a similar kind of aging effect in the outdoor environment. The applicant was asked to provide a discussion of the actual Group B2 and B4 galvanizedsteel, aluminum, and stainless steel VYNPS components which are within the scope of licenserenewal and exposed to an outdoor air environment. In addition, the applicant was asked to discuss the location of these components at VYNPS and how they are protected from constant wetting and drying conditions.The applicant's technical personnel stated that loss of material due to pitting and crevicecorrosion of aluminum and stainless steel components in an outdoor environment is not applicable if the atmospheric environment is non-aggressive. The ambient environment at VYNPS is not chemically polluted by vapors of sulfur dioxide (SO
: 2) or other similar substancesand the external environment does not contain saltwater or high chloride content. In this non-aggressive environment, the occasional wetting and drying from normal outdoor weather does not result in any significant loss of material in aluminum or stainless steel components. The conclusion that no aging effects require management for these materials in an outdoor air environment is supported by operating experience and by previously approved staff positions documented in the Joseph M. Farley SER (NUREG-1825, page 3-314).
3-424The applicant stated that the components that may be considered in the B2 and B4 groupingconsists of those line items in LRA Table 3.5.2-6 including the plant-specific Note 503. Note 503 provides the basis for concluding the environment is non-aggressive and the conclusion that there are no aging effects requiring management.The applicant stated that loss of material is not an applicable aging effect for stainless steel oraluminum components in outdoor air. The ambient environment at VYNPS is not chemically polluted by vapors of SO 2 or other similar substances and the external environment does notcontain saltwater or high chlorides. Therefore, loss of material due to pitting and crevice corrosion is not an AERM for aluminum and stainless steel components exposed to the external environment.The applicant stated that the AMR results for galvanized steel components in outdoor air shouldindicate loss of material as an aging effect with structures monitoring as the AMP . In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.1, Item 3.5.1-50 is revised to include the following in the discussion column: "Consistent with NUREG-1801 for galvanized steel components in outdoor air. The Structures Monitoring Program will manage loss of material."The staff reviewed the applicant's Structures Monitoring Program. This evaluation isdocumented in SER Section 3.0.3.2.17. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.During the audit and review, the staff noted that in LRA Table 3.5.2-5 (page 3.5-65), forcomponent transmission towers, material galvanized steel in an exposed to weather environment; the aging effect is none. The staff referenced the first question above and asked the applicant to explain how this component is protected from constant wetting and drying conditions.During interviews with the applicant's technical personnel, the applicant's staff stated that asidentified in the response to the first question above, loss of material is the AERM and the Structures Monitoring Program is the AMP. This is consistent with the GALL Report, Volume 2, Item III.B4-7, summarized in LRA Table 3.5.1, Item 3.5.1-50, and note C applies. In a letterdated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to indicate loss of material as an AERM with the Structures Monitoring Program as the AMP and the GALL Report Volume 2 item as III.B4-7 with a Note C in LRA Table 3.5.2-5 for transmissiontowers with a material of galvanized steel in an exposed to weather environment. The staff review the applicant's response and finds it acceptable.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-71), forcomponent conduit, material galvanized steel in an exposed to weather environment; the aging effect is none. The staff referenced the first question above and asked the applicant to explain how this component is protected from constant wetting and drying conditions.
3-425During interviews with the applicant's technical personnel, the applicant's staff stated that asidentified in the response to the first question above, loss of material is the AERM and the Structures Monitoring Program is the AMP. This is consistent with the GALL Report, Volume 2, Item III.B4-7, summarized in LRA Table 3.5.1, Item 3.5.1-50, and note C applies. In a letterdated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to indicate loss of material as an AERM with the Structures Monitoring Program as the AMP and the GALL Report Volume 2 item as III.B4-7 with a Note C in LRA Table 3.5.2-6 for conduit with amaterial of galvanized steel in an exposed to weather environment.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-71), forcomponent conduit support, material galvanized steel in an exposed to weather environment; the aging effect is none. The staff referenced the first question above and asked the applicant to explain how this component is protected from constant wetting and drying conditions.During interviews with the applicant's technical personnel, the applicant's staff stated that asidentified in the response to the first question above, loss of material is the AERM and the Structures Monitoring Program is the AMP. This is consistent with the GALL Report, Volume 2, Item III.B4-7, summarized in LRA Table 3.5.1, Item 3.5.1-50, and Note C applies. In a letterdated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to indicate loss of material as an AERM with the Structures Monitoring Program as the AMP and the GALL Report Volume 2 item as III.B4-7 with a Note C in LRA Table 3.5.2-6 for conduitsupport with a material of galvanized steel in an exposed to weather environment.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-72), forcomponent electrical and instrument panels and enclosures, material galvanized steel in an exposed to weather environment; the aging effect is none. The staff referenced the first question above and asked the applicant to explain how this component is protected from constant wetting and drying conditions.During interviews with the applicant's technical personnel, the applicant's staff stated that asidentified in the response to the first question above, loss of material is the AERM and the Structures Monitoring Program is the AMP. This is consistent with the GALL Report, Volume 2, Item III.B4-7, summarized in LRA Table 3.5.1, Item 3.5.1-50, and note C applies. In a letterdated July 14, 2006, the applicant stated amended its LRA. The applicant stated that the LRA is revised to indicate loss of material as an AERM with the Structures Monitoring Program as the AMP and the GALL Report Volume 2 item as III.B4-7 with a Note C in LRA Table 3.5.2-6 forelectrical and instrument panels and enclosures with a material of galvanized steel in an exposed to weather environment.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.
3-426During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-78), forcomponent structural bolting, material galvanized steel in an exposed to weather environment; the aging effect is none. The staff referenced the first question above and asked the applicant to explain how this component is protected from constant wetting and drying conditions.During interviews with the applicant's technical personnel, the applicant's staff stated that asidentified in the response to the first question above, loss of material is the AERM and the Structures Monitoring Program is the AMP. This is consistent with the GALL Report, Volume 2, Item III.B4-7, summarized in LRA Table 3.5.1, Item 3.5.1-50, and Note C applies. In a letterdated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to indicate loss of material as an AERM with the Structures Monitoring Program as the AMP and the GALL Report Volume 2 item as III.B4-7 with a Note C in LRA Table 3.5.2-6 for structuralbolting with a material of galvanized steel in an exposed to weather environment.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.5.2.1.15  Loss of Material Due to General and Pitting Corrosion For loss of material due to general and pitting corrosion of steel support members; welds, boltedconnections; support anchorage to building structure exposed to indoor uncontrolled air or outdoor air the GALL Report recommends programs consistent with GALL AMP XI.S3, "ASME Code, Section XI, Subsection IWF."During the audit and review, the staff noted that loss of material of steel reactor vessel supportassembly, reactor vessel stabilizer supports, torus external supports (columns, saddles),
anchorage/embedments, base plates, component and piping supports ASME Code Class 1, 2, 3 and MC, anchor bolts, and ASME Code Class 1, 2, 3 and MC supports bolting exposed to a protected from weather environment and anchorage/embedments, base plates, component and piping supports ASME Code Class 1, 2, 3 and MC, anchor bolts, ASME Code Class 1, 2, 3 and MC supports bolting exposed to a weather environment is managed using the Inservice Inspection Program, which is a plant-specific program instead of the recommended GALL AMP XI.S3.The staff reviewed the applicant's Inservice Inspection Program and its evaluation isdocumented in SER Section 3.0.3.3.3. The staff finds that the applicant's Inservice Inspection Program satisfied criteria of SRP-LR Appendix A.1 and encompasses the ASME Code, Section XI Subsection IWF requirements for managing the loss of material for ASME Code Class 1, 2, and 3 steel piping supports and steel component supports within containment.On the basis that the applicant's plant-specific Inservice Inspection Program includes the samerequirements for inspection and detection of loss of material for ASME Code, Class 1, 2, and 3 steel piping supports and steel component supports within containment as the ASME Code, Section XI Subsection IWF, the staff finds it to be an acceptable management program for loss of material of the components listed above.
3-427For loss of material due to general and pitting corrosion of carbon steel vent header supportexposed to fluid environment (LRA page 3.5-54), the GALL Report line item shown is III.B1.1-13,LRA Table 1, Item 3.5.1-53 is referenced, and the AMP shown is the Inservice Inspection-IWF Program. The staff noted that GALL Report Line Item III.B1.1-13 is for an indoor uncontrolled airor outdoor air environment. In RAI 3.5.1-53-W-1, the staff asked the applicant to explain why GALL Report Line Item III.B1.1-11 (treated water environment), LRA Table 1, Item 3.5.1-49, andthe Water Chemistry Control - BWR Program are not included in this AMR line item.By letter dated September 5, 2006 the applicant provided its response. The applicant stated thatsince portions of the carbon steel vent header supports are below the water level in the torus, application of GALL Report Line Item III.B1.1-11 is appropriate for the vent header supports. Theapplicant has also revised this AMR line item to reflect this change. The staff reviewed the applicant's response and determined it acceptable. Therefore, the staff's concern described in RAI 3.5.1-53-W-1 is resolved.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.3.5.2.1.16  None (Galvanized Steel and Aluminum Support Members; Welds; BoltedConnections; Support Anchorage to Building Structure)During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-72), forcomponent electrical and instrument panels and enclosures, material galvanized steel in a protected from weather environment, the aging effect is none. The GALL Report line item referenced is III.B3-3, which is for the following components: support members; welds; boltedconnections; support anchorage to building structure. The applicant was asked to explain why the LRA AMR line item has a Note A shown instead of a Note C, different component with respect to the GALL Report line item. Or as an alternative, a letter note A with a number note explaining that the component is different.During interviews with the applicant's technical personnel, the applicant's staff stated that theGALL Report does not mention every type of component that may be subject to AMR (e.g.,
panel is not in the GALL Report) nor does the terminology used at a specific plant always align with that used in the GALL Report. Consequently, matching plant components to the GALL Report components is occasionally subjective. In this particular case, panels, which have no specific function other than to support and protect electrical equipment, was considered a support member and note A was applied. The use of either note A or C has no real impact on the AMR results.In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRATable 3.5.2-6 is revised to change note A to note C for electrical and instrument panels and enclosures with a material of galvanized steel in a protected from weather environment. Aging effect and associated AMP are unchanged.On the basis of its review of the applicant's response, the staff finds the response acceptableand the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
3-428During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-73), forcomponent flood curb, material galvanized steel in a protected from weather environment, the aging effect is none. The GALL Report line item referenced is III.B5-3, which is for the followingcomponents: Support members; welds; bolted connections; support anchorage to building structure. The applicant was asked to explain why the LRA AMR line item has a Note A shown instead of a Note C, different component with respect to the GALL Report line item. Or as an alternative, a letter note A with a number note explaining that the component is different.During interviews with the applicant's technical personnel, the applicant's staff stated that unlikethe conduits and panels compared to supports in other questions, the component flood curb should not have been considered a match. Note C should be applied here; although the use of either note A or C has no real impact on the AMR results. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.2-6 is revised to change note A to note C for flood curb with a material of galvanized steel in a protected from weather environment. Aging effect and associated AMP are unchanged.On the basis of its review of the applicant's response, the staff finds the response acceptableand the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed consistent with its AMRs. Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.5.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is RecommendedSummary of Information in the Application. In LRA Section 3.5.2.2, the applicant furtherevaluates aging management, as recommended by the GALL Report, for the SC supports components and provides information concerning how it will manage the following effects of aging:  (1)PWR and BWR containments:
* aging of inaccessible concrete areas
* cracks and distortion due to increased stress levels from settlement; reduction offoundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundations if not covered by the structures monitoring program
* reduction of strength and modulus of concrete structures due to elevatedtemperature
* loss of material due to general, pitting, and crevice corrosion 3-429
* loss of prestress due to relaxation, shrinkage, creep, and elevated temperature
* cumulative fatigue damage
* cracking due to stress-corrosion cracking
* cracking due to cyclic loading
* loss of material (scaling, cracking, and spalling) due to freeze-thaw
* cracking due to expansion and reaction with aggregate, and increase in porosityand permeability due to leaching of calcium hydroxide  (2)safety-related and other structures and components supports:
* aging of structures not covered by the structures monitoring program
* aging management of inaccessible areas
* reduction of strength and modulus of concrete structures due to elevatedtemperature
* aging management of inaccessible areas for Group 6 structures
* cracking due to stress-corrosion cracking and loss of material due to pitting andcrevice corrosion
* aging of supports not covered by the structures monitoring program
* cumulative fatigue damage due to cyclic loading  (3)quality assurance for aging management of nonsafety-related components Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicantclaimed consistency with the report and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations against the criteria contained in SRP-LR Section 3.5.2.2. The staff's review of the applicant's further evaluation follows.3.5.2.2.1  PWR and BWR Containments The staff reviewed LRA Section 3.5.2.2.1 against SRP-LR Section 3.5.2.2.1 criteria, whichaddress several areas:Aging of Inaccessible Concrete Areas. The staff reviewed LRA Section 3.5.2.2.1.1 against thecriteria in SRP-LR Section 3.5.2.2.1.1.In LRA Section 3.5.2.2.1.1, the applicant addressed increase in porosity and permeability,cracking, loss of material (spalling, scaling) due to aggressive chemical attack, and cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel.SRP-LR Section 3.5.2.2.1.1 states that increases in porosity and permeability, cracking, loss ofmaterial (spalling, scaling) due to aggressive chemical attack, and cracking, loss of bond, and 3-430loss of material (spalling, scaling) due to corrosion of embedded steel may occur in inaccessibleareas of PWR and BWR concrete and steel containments. The existing program relies on ASME Code, Section XI, Subsection IWL to manage these aging effects; however, the GALL Report recommends further evaluation of plant-specific programs to manage the aging effects for inaccessible areas in aggressive environments.The applicant stated, in the LRA, that VYNPS has a Mark I free standing steel containmentlocated within the reactor building. Inaccessible and accessible concrete areas are designed in accordance with ACI specification ACI 318-63, "Building Code Requirements for Reinforced Concrete," which results in low permeability and resistance to aggressive chemical solutions by requiring the following:
* high cement content
* low water-to-cement ratio
* proper curing
* adequate air entrainmentIn addition, as stated in the LRA, VYNPS concrete also meets requirements of later ACIguide ACI 201.2R-77, "Guide to Durable Concrete," since both documents use the same ASTMstandards for selection, application and testing of concrete.Furthermore, as stated in the LRA, the below-grade environment is not aggressive (pH greaterthan 5.5, chlorides less than 500 ppm, and sulfates less than 1,500 ppm). Concrete was provided with air content between 3 percent and 5 percent and a water/cement ratio between 0.44 and 0.60. Therefore, increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack, and cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel are not applicable for concrete in inaccessible areas. The absence of concrete aging effects is confirmed in accordance with the Structures Monitoring Program.The staff finds that these aging effects are not applicable to the VYNPS Mark I free standingsteel containment. The listed possible aging effects apply to concrete elements of PWR containments and concrete BWR containments. The VYNPS Mark I steel containment is located within the concrete reactor building and the previous applicant discussion is for that concrete
 
structure.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.5.2.2.1.1 criteria. For those line items that apply to LRA Section 3.5.2.2.1.1, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-431Cracks and Distortion Due to Increased Stress Levels from Settlement; Reduction of FoundationStrength, Cracking, and Differential Settlement Due to Erosion of Porous ConcreteSubfoundations, If Not Covered by the Structures Monitoring Program. The staff reviewed LRASection 3.5.2.2.1.2 against the criteria in SRP-LR Section 3.5.2.2.1.2.In LRA Section 3.5.2.2.1.2, the applicant stated that for the crack and distortion due to increasedstress levels from settlement; reduction of foundation strength, cracking and differential settlement due to erosion of porous concrete subfoundations, if not covered by the Structures Monitoring Program, this aging effect is not applicable to VYNPS.SRP-LR Section 3.5.2.2.1.2 states that cracks and distortion due to increased stress levels fromsettlement may occur in PWR and BWR concrete and steel containments. Also, reduction of foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundations may occur in all types of PWR and BWR containments. The existing program relies on structures monitoring to manage these aging effects. Some plants may rely on a de-watering system to lower the site ground water level. If the plant's CLB credits a de-watering system, the GALL Report recommends verification of the continued functionality of the de-watering system during the period of extended operation. The GALL Report recommends no further evaluation if this activity is within the scope of the applicant's structures monitoring program.In addition, as stated in the LRA, VYNPS has a Mark I free standing steel containment locatedwithin the reactor building and supported by the reactor building foundation. VYNPS does not rely on a de-watering system for control of settlement. Category 1 structures are founded on sound bedrock which prevents significant settlement. Additionally, concrete within five feet of the highest known ground water level is protected by membrane waterproofing. This membrane protects the reactor building concrete against exposure to groundwater. VYNPS was not identified in IN 97-11 as a plant susceptible to erosion of porous concrete subfoundations.
Groundwater was not aggressive during plant construction and there is no indication that groundwater chemistry has significantly changed. No changes in groundwater conditions have been observed at VYNPS. As a result, cracking and distortion due to increased stress levels from settlement; reduction of foundation strength, cracking and differential settlement due to erosion of porous concrete subfoundations are not applicable to VYNPS concrete structures.During the audit and review, the applicant stated that the crack and distortion due to increasedstress levels from settlement; reduction of foundation strength, cracking and differential settlement due to erosion of porous concrete subfoundations, if not covered by the Structures Monitoring Program are not plausible aging effects due to the nonexistence of these aging mechanisms. The applicant stated that the aging effects due to settlement are not expected at VYNPS for the Mark I steel containment since it is located within the reactor building and supported by the reactor building foundation. The reactor building is founded on sound bedrock which prevents significant settlement. In addition, there is no porous concrete subfoundation below the reactor building of concern. On the basis of its audit and review, the staff determined that crack and distortion due toincreased stress levels from settlement; reduction of foundation strength, cracking and differential settlement due to erosion of porous concrete subfoundations are not plausible aging 3-432effects due to the nonexistence of these aging mechanisms at VYNPS. The staff finds that theseaging effects and aging effect mechanisms are not applicable to the VYNPS Mark I free standing steel containment.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.5.2.2.1.2 criteria. For those line items that apply to LRA Section 3.5.2.2.1.2, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. Thestaff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.1.3.In LRA Section 3.5.2.2.1.3, the applicant stated that for the reduction of strength of modulus ofconcrete structures due to elevated temperature, this aging effect is not applicable to VYNPS.SRP-LR Section 3.5.2.2.1.3 states that reduction of strength and modulus of concrete due toelevated temperatures may occur in PWR and BWR concrete and steel containments. The implementation of the requirements of 10 CFR 50.55a and ASME Code, Section XI, Subsection IWL would not be able to identify the reduction of strength and modulus of concrete due to elevated temperature. ASME Code, Section III, Division 2, Subsection CC-3400, specifiesthe concrete temperature limits for normal operation or any other long-term period. The GALL Report recommends further evaluation of plant-specific AMPs if any portion of the concrete containment components exceeds specified temperature limits (i.e., general area temperature greater than 60 C (150 F) and local area temperature greater than 93 C (200 F)).The UFSAR states that the ambient temperature in the drywell is maintained between 135 F and 165 F. With a two inch air gap between the drywell shell and the concrete containment,there will be a sufficient temperature drop across the gap so that the concrete will remain well below the 150 F limit specified in the ASME Code. Transfer of heat across an air gap relies onradiant heat transfer, which is very inefficient. As a result, there will be no reduction in the strength and modulus of the concrete due to elevated temperature as a result of the temperature in the drywell.In addition, the applicant stated, that ASME Code, Section III, Division 2, Subsection CCindicates that aging due to elevated temperature exposure is not significant as long as concrete general area temperatures do not exceed 150F and local area temperatures do not exceed 200F. During normal operation, areas within primary containment are within these temperaturelimits. Therefore, reduction of strength and modulus of concrete structures due to elevated temperature is not an AERM for VYNPS containment concrete. On the basis of its audit and review, the staff determined that the reduction of strength andmodulus for concrete structures due to elevated temperature are not plausible aging effects due to the nonexistence of these aging mechanisms. The staff also finds that these aging effects and 3-433aging effect mechanisms are not applicable to the VYNPS Mark I free standing steelcontainment. The aging effects due to elevated temperature are not expected at VYNPS for the concrete associated with the Mark I steel containment since general areas temperatures within the primary containment do not exceed 150F and local area temperatures do not exceed 200F. On this basis, the staff concludes that these aging effects are not applicable to theVYNPS containment.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.5.2.2.1.3 criteria. For those line items that apply to LRA Section 3.5.2.2.1.3, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).Loss of Material Due to General, Pitting and Crevice Corrosion. The staff reviewed LRASection 3.5.2.2.1.4 against the criteria in SRP-LR Section 3.5.2.2.1.4.In LRA Section 3.5.2.2.1.4, the applicant addressed the loss of material of steel elements ofaccessible and inaccessible areas for all types of PWR and BWR containments due to general, pitting and crevice corrosion.SRP-LR Section 3.5.2.2.1.4 states that loss of material due to general, pitting, and crevicecorrosion may occur in steel elements of accessible and inaccessible areas for all types of PWRand BWR containments. The existing program relies on requirements of ASME Code, Section XI, Subsection IWE, and 10 CFR Part 50, Appendix J, to manage this aging effect. The GALL Report recommends further evaluation of plant-specific programs to manage this aging effect for inaccessible areas if corrosion is significant.In LRA Section 3.5.2.2.1.4, the applicant addressed loss of material of steel elements ofaccessible and inaccessible areas for all types of PWR and BWR containments due to general, pitting and crevice corrosion. The applicant stated, in the LRA, that VYNPS's containment is a Mark I steel containment located within the reactor building. VYNPS reactor building concrete in contact with the drywell shell is designed in accordance with specification ACI 318-63. Theconcrete meets the recommendations of later ACI guide 201.2R-77, since both documents use the same ASTM standards for selection, application and testing of concrete. Concrete is monitored for cracks in accordance with the Structures Monitoring Program. The drywell steel shell and the moisture barrier where the drywell shell becomes embedded in the drywell concrete floor are inspected in accordance with the Containment Inservice Inspection (IWE)
Program.
3-434The applicant also stated that to prevent corrosion of the lower part of the drywell shell, theinterior and exterior surfaces are protected from any contact with the atmosphere by complete concrete encasement. It is not credible for ground water to reach the drywell shell, assuming a crack in the concrete, since the concrete at this location is greater than 8 feet thick and poured in multiple separate horizontal planes. The exterior surface of the drywell shell at the sand cushion interface is effectively drained and protected from condensation or water that might enter the air gap from above. Therefore, significant corrosion of the drywell shell is not expected.On the basis of its audit and review, the staff determined that corrosion is not significant forinaccessible areas of the VYNPS containment. In the LRA, the applicant stated that the reactor building concrete in contact with the drywell shell is designed in accordance with ACI 318-63,and meets the recommendations of guideline ACI 201.2R-77. Accessible concrete of the reactorbuilding is monitored for penetrating cracks in accordance with the VYNPS Structures Monitoring Program. In addition, the applicant stated that the accessible portions of the steel drywell and moisture barrier where the drywell shell becomes embedded in the concrete floor are inspected in accordance with the Containment Inservice Inspection (IWE) Program and Structures Monitoring Program. During interviews with the applicant's technical personnel, the applicant's staff stated that operating experience has demonstrated that the aging effect of loss of material due to corrosion has not been significant for the VYNPS containment. The staff finds that no additional plant-specific AMP was required to manage inaccessible areas of the containment drywell shell and associated components.In the last paragraph of the discussion column of LRA Table 3.5.1, Item 3.5.1-5, the applicantstated that:The drywell steel where the drywell shell is embedded is inspected in accordancewith the Containment Inservice Inspection (IWE) Program and Structures Monitoring Program.The staff noted that this is an impossible inspection. During the audit and review, the staff askedthe applicant to explain if this statement should have agreed with LRA Section 3.5.2.2.1.4 that stated: The drywell steel shell and the moisture barrier where the drywell shell becomesembedded in the drywell concrete floor are inspected in accordance with the Containment Inservice Inspection (IWE) Program and Structures Monitoring.In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRATable 3.5.1, Item 3.5.1-5, the discussion column last paragraph is revised to read:The drywell steel shell and the moisture barrier where the drywell shell becomesembedded in the drywell concrete floor are inspected in accordance with the Containment Inservice Inspection (IWE) Program.Also, LRA Section 3.5.2.2.1.4 is revised to delete from the end of the first paragraph, the phrase"and Structures Monitoring Program." The drywell to floor moisture barrier will be inspected in accordance with the Containment Inservice Inspection (IWE) Program only. The Structures Monitoring Program is not used.
3-435On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.Based on the programs identified above, the staff concludes that the applicant's meet SRP-LRSection 3.5.2.2.1.4 criteria. For those line items that apply to LRA Section 3.5.2.2.1.4, the staff finds that the LRA isconsistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature
.LRA Section 3.5.2.2.1.5 states that loss of prestress forces due to relaxation, shrinkage, creep,and elevated temperature is a TLAA as required by 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.5 documents the staff's review of the applicant's evaluation of this TLAA.SRP-LR Section 3.5.2.2.1.5, stated that loss of prestress forces due to relaxation, shrinkage,creep, and elevated temperature for PWR prestressed concrete containments and BWR Mark II prestressed concrete containments is a TLAA as required by 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c).The applicant stated, in the LRA, that for the loss of prestress due to relaxation, shrinkage,creep, and elevated temperature, this aging effect is not applicable to VYNPS. VYNPS is a Mark I containment structure and does not incorporate prestress concrete in its design. Therefore, loss of prestress due to relaxation, shrinkage, creep, and elevated temperature is not an applicable aging effect. The staff finds that because VYNPS is a BWR with a Mark I containment, the aging effect loss of prestress due to relaxation, shrinkage, creep, and elevated temperature is not applicable to VYNPS.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.6 states fatigue analyses of suppressionpool steel shells (including welded joints) and penetrations (including penetration sleeves,dissimilar metal welds, and penetration bellows) are TLAAs as required by 10 CFR 54.3.
Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.6 documents the staff's review of the applicant's evaluation of this TLAA.In the discussion column of LRA Table 3.5.1, Item 3.5.1-9, the applicant stated: "Not applicable.See Section 3.5.2.2.1.6." However, during the audit and review, the staff noted the following statement was made in LRA Section 3.5.2.2.1.6:Fatigue TLAAs for the steel drywell, torus, and associated penetrations areevaluated and documented in Section 4.6.
3-436The components associated with LRA Table 3.5.1, Item 3.5.1-9 are: penetration sleeves, penetration bellows; suppression pool shell, unbraceddowncomers. The applicant was asked to explain how LRA Table 3.5.1, Item 3.5.1-9 was not applicable whena fatigue TLAA has been performed for the torus and penetrations. Also the applicant was asked to explain why the vent line, vent header and vent line bellows are not listed in LRA Sections 3.5.2.2.1.6 and 4.6 as referenced in LRA Table 3.5.1, Item 3.5.1-8.In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRATable 3.5.2-1 is revised to add the following line: torus mechanical penetrations, PB, SSR carbon steel, protected from weather,cracking (fatigue), TLAA-metal fatigue, II.B4-4 (C-13), 3.5.1-9, note A.The staff finds that the evaluation of the drywell to torus vent system fatigue analysis finds that itwas not a TLAA. The significant contributor to fatigue of the vent system is post-LOCA chugging, a once in plant-life event. As there will still be only one design basis LOCA for the life of the plant, including the period of extended operation, this analysis is not based on a time-limited assumption and is not a TLAA. Since fatigue for the vent system is event driven and is not an age related effect, in a letter datedJuly 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.2-1 is revised to delete the following line:Drywell to torus vent system, PB, SSR, carbon steel, protected from weather,cracking (fatigue), TLAA-metal fatigue, II.B1.1-4 (C-21), 3.5.1-8, A.Also, the discussion column entry for LRA Table 3.5.1, Item 3.5.1-8 is revised to read as follows:Fatigue analysis is a TLAA for the torus shell. Fatigue of the torus to drywell ventsystem is event driven and the analysis is not a TLAA. See Section 3.5.2.2.1.6.In addition the discussion column entry of LRA Table 3.5.1, Item 3.5.1-9 is revised to read asfollows:Fatigue analysis is a TLAA for the torus penetrations. See Section 3.5.2.2.1.6.Also, the discussion of LRA Section 3.5.2.2.1.6 is revised to read as follows:TLAA are evaluated in accordance with 10 CFR 54.21(c) as documented inSection 4. Fatigue TLAAs for the torus and associated penetrations are evaluated and documented in Section 4.6.
3-437LRA Section 3.5.2.3, Time-Limited Aging Analyses, is revised to read as follows:TLAA identified for structural components and commodities include fatigueanalyses for the torus and torus penetrations. These topics are discussed in Section 4.6.On the basis of its review, the staff finds that the applicant appropriately addressed the agingeffect/mechanism, as recommended by the GALL Report.Cracking Due to SCC. The staff reviewed LRA Section 3.5.2.2.1.7 against the criteria in SRP-LRSection 3.5.2.2.1.7.In LRA Section 3.5.2.2.1.7, the applicant stated that for cracking due to SCC, this aging effect isnot applicable to VYNPS.SRP-LR Section 3.5.2.2.1.7 states that cracking due to SCC of stainless steel penetrationsleeves, penetration bellows, and dissimilar metal welds may occur in all types of PWR and BWR containments. Cracking due to SCC also may occur in stainless steel vent line bellows for BWR containments. The existing program relies on the requirements of ASME Code, Section XI, Subsection IWE and 10 CFR Part 50, Appendix J, to manage this aging effect. The GALL Report recommends further evaluation of additional appropriate examinations/evaluationsimplemented to detect these aging effects for stainless steel penetration sleeves, penetration bellows and dissimilar metal welds, and stainless steel vent line bellows.The applicant stated, in the LRA, that for the cracking due to SCC, this aging effect is notapplicable to VYNPS. The GALL Report recommends further evaluation of inspection methods to detect cracking due to SCC, since visual VT-3 examinations may be unable to detect this aging effect. Potentially susceptible components at VYNPS are penetration sleeves and bellows.The applicant also stated that SCC becomes significant for stainless steel if tensile stresses anda corrosive environment exist. The stresses may be applied (external) or residual (internal). The normal environment inside the drywell is dry. The penetration components are not exposed to corrosive environments. Therefore, SCC is not an AERM for the penetration sleeves and bellows, since the conditions necessary for SCC do not exist. On the basis of its review, the staff finds that cracking due to SCC for penetration sleeves andbellows is not applicable to VYNPS since the conditions necessary for SCC do not exist.In LRA Table 3.5.1, Item 3.5.1-10, the applicant stated that cracking due to SCC for stainlesssteel penetration sleeves and penetration bellows is not applicable. Also, in LRA Table 3.5.1, Item 3.5.1-11, the applicant stated that cracking due to SCC for stainless steel vent line bellows is not applicable.
3-438During the audit and review, the applicant was asked to explain if the VYNPS ContainmentInservice Inspection Program and Containment Leak Rate Program are used currently to detect cracking of stainless steel penetration sleeves, penetration bellows and vent line bellows by inspection and testing. The applicant was also asked to explain why it is not more appropriate to take credit for these two programs to detect cracking without the need for additional enhanced examinations then to say not applicable.The applicant staff stated that the GALL Report's referenced programs involve visual inspectionsand leak testing which are not optimum methods for managing SCC. Therefore, when possible, it is more appropriate to assess the conditions and identify whether the applicable aging effects require management. As stated in LRA Section 3.5.2.2.1.7, SCC is not an AERM for the penetration sleeves and bellows, since the conditions necessary for SCC do not exist. However, these components are evaluated for aging effects (such as cracking) requiring management as shown in LRA Table 3.5.2-1.On the basis that VYNPS does not have the conditions necessary for this aging effect, the stafffinds that this aging effect is not applicable to VYNPS.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.5.2.2.1.7 criteria. For those line items that apply to LRA Section 3.5.2.2.1.7, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).Cracking Due to Cyclic Loading. The staff reviewed LRA Section 3.5.2.2.1.8 against the criteriain SRP-LR Section 3.5.2.2.1.8.In LRA Section 3.5.2.2.1.8, the applicant addressed cracking of penetration sleeves, penetrationbellows, and torus pool steel due to cyclic loading.SRP-LR Section 3.5.2.2.1.8 states that cracking due to cyclic loading of suppression pool steeland stainless steel shells (including welded joints) and penetrations (including penetrationsleeves, dissimilar metal welds, and penetration bellows) may occur in all types of PWR and BWR containments and BWR vent header, vent line bellows, and downcomers. The existing program relies on the requirements of ASME Code, Section XI, Subsection IWE and 10 CFR Part 50, Appendix J, to manage this aging effect; however, visual examination (VT-3) may not detect fine cracks. The GALL Report recommends further evaluation for detection of this aging effect.The applicant stated, in the LRA, that cyclic loading can lead to cracking of penetration sleeves,penetration bellows, and torus pool steel. If a CLB analysis does not exist, further evaluation is recommended of inspection methods to detect cracking due to cyclic loading since visual VT-3 examinations may be unable to detect this aging effect.The analysis of cracking due to cyclic loading of the drywell, torus, and associated penetrationsis a TLAA which is evaluated as documented in LRA Section 4.6.
3-439In the discussion column of LRA Table 3.5.1, Items 3.5.1-12 and 3.5.1-13, the applicant did notmake reference to LRA Section 3.5.2.2.1.8 for further evaluation. During the audit and review, the applicant was asked to explain why this link was not made to the further evaluation section.
Also the applicant was asked to explain the need for augmented ultrasonic exams to detect fine cracks since a CLB fatigue analysis does exist.In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA isrevised as follows:    (1)For clarification, the discussion column of VYNPS Table 3.5.1, Line Items 3.5.1-12 and3.5.1-13 is revised to add the following statement at the end of the existing information.
"See Section 3.5.2.2.1.8."  (2)LRA Section 3.5.2.2.1.8 is revised to read as follows:Cyclic loading can lead to cracking of steel and stainless steelpenetration bellows, and dissimilar metal welds of BWR containments and BWR suppression pool shell and downcomers.
Cracking due to cyclic loading is not expected to occur in the drywell, torus and associated penetration bellows, penetration sleeves, unbraced downcomers, and dissimilar metal welds. A review of plant operating experience did not identify cracking of the components, and primary containment leakage has not been identified as a concern. Nonetheless the existing Containment Leak Rate Program with augmented ultrasonic exams and Containment Inservice Inspection-IWE, will continue to be used to detect cracking. Observed conditions that have the potential for impacting an intended function are evaluated or corrected in accordance with the corrective action process. The Containment Inservice Inspection-IWE and Containment Leak Rate programs are described in Appendix B.Based on the programs identified above, staff concludes that the applicant's programs meet theSRP-LR Section 3.5.2.2.1.8 criteria. For those line items that apply to LRA Section 3.5.2.2.1.8, the staff finds that the LRA isconsistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).Loss of Material (Scaling, Cracking, and Spalling) Due to Freeze-Thaw. The staff reviewed LRASection 3.5.2.2.1.9 against the criteria in SRP-LR Section 3.5.2.2.1.9.In LRA Section 3.5.2.2.1.9, the applicant stated that for the loss of material (scaling, cracking,and spalling) due to freeze-thaw, this aging effect is not applicable to VYNPS.
3-440SRP-LR Section 3.5.2.2.1.9 states that loss of material (scaling, cracking, and spalling) due tofreeze-thaw may occur in PWR and BWR concrete containments. The existing program relies on ASME Code, Section XI, Subsection IWL to manage this aging effect. The GALL Report recommends further evaluation of this aging effect for plants located in moderate to severe weather conditions.The applicant stated, in the LRA, that for the loss of material (scaling, cracking, and spalling)due to freeze-thaw, this aging effect is not applicable to VYNPS. VYNPS has a Mark I free standing steel containment located within the reactor building. Loss of material (scaling, cracking, and spalling) due to freeze-thaw is applicable only to concrete containments.
Therefore, loss of material and cracking due to freeze-thaw do not apply. The staff finds that since VYNPS is a BWR with a Mark I containment, the aging effect loss of material (scaling, cracking, and spalling) due to freeze-thaw is not applicable to VYNPS.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.5.2.2.1.9 criteria. For those line items that apply to LRA Section 3.5.2.2.1.9, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).Cracking Due to Expansion and Reaction with Aggregate and Increase in Porosity andPermeability Due to Leaching of Calcium Hydroxide. The staff reviewed LRASection 3.5.2.2.1.10 against the criteria in SRP-LR Section 3.5.2.2.1.10.In LRA Section 3.5.2.2.1.10, the applicant stated that for the cracking due to expansion andreaction with aggregate, and increase in porosity and permeability due to leaching of calcium hydroxide, this aging effect is not applicable to VYNPS.SRP-LR Section 3.5.2.2.1.10 states that cracking due to expansion and reaction with aggregateand increase in porosity and permeability due to leaching of calcium hydroxide may occur in concrete elements of PWR and BWR concrete and steel containments. The existing program relies on ASME Code, Section XI, Subsection IWL to manage these aging effects. The GALL Report recommends further evaluation if concrete was not constructed in accordance with ACI 201.2R-77 recommendations. The applicant stated, in the LRA, that for the cracking due to expansion and reaction withaggregate, and increase in porosity and permeability due to leaching of calcium hydroxide, this aging effect is not applicable to VYNPS. VYNPS has a Mark I free standing steel containment located within the reactor building. In accordance with the GALL Report, aging management is 3-441not required because VYNPS containment concrete (basemat) is designed in accordance withspecification ACI 318-63, which requires that the potential reactivity of aggregates be acceptable based on testing in accordance with ASTM C-289 and C-295. The staff finds that since VYNPS is a BWR with a Mark I containment, the aging effect cracking due to expansion and reaction with aggregate, and increase in porosity and permeability due to leaching of calcium hydroxide is not applicable to VYNPS.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.5.2.2.1.10 criteria. For those line items that apply to LRA Section 3.5.2.2.1.10, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.5.2.2.2  Safety-Related and Other SC Supports The staff reviewed LRA Section 3.5.2.2.2 against SRP-LR Section 3.5.2.2.2 criteria, whichaddress several areas:Aging of Structures Not Covered by Structures Monitoring Program. The staff reviewed LRASection 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1.In LRA Section 3.5.2.2.2.1, the applicant addresses the aging of structures not covered by theStructures Monitoring Program.SRP-LR Section 3.5.2.2.2.1 states that the GALL Report recommends further evaluation ofcertain structure-aging effect combinations not covered by structures monitoring programs, including: (1) cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel for Groups 1-5, 7, and 9 structures, (2) increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to aggressive chemical attack for Groups 1-5, 7, and 9 structures, (3) loss of material due to corrosion for Groups 1-5, 7, and 8 structures, (4) loss of material (spalling, scaling) and cracking due to freeze-thaw for Groups 1-3, 5, and 7-9 structures, (5) cracking due to expansion and reaction with aggregates for Groups 1-5 and 7-9 structures, (6) cracks and distortion due to increased stress levels from settlement for Groups 1-3 and 5-9 structures, and (7) reduction in foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundation for Groups 1-3 and 5-9 structures. The GALL Report recommends further evaluation only for structure-aging effect combinations not within structures monitoring programs. In addition, lock-up due to wear may occur in Lubrite radial beam seats in BWR drywells, RPV support shoes for PWR with nozzle supports, steam generator supports, and other sliding support bearings and sliding support surfaces. The existing program relies on structures monitoring or ASME Code, Section XI, Subsection IWF, to manage this aging effect. The GALL Report recommends further evaluation only for structure-aging effect combinations not within the ISI (IWF) or structures monitoring programs.
3-442The staff finds that the applicant has included the eight SRP-LR Section 3.5.2.2.2.1structure/aging effect combinations in its Structures Monitoring Program and no further evaluation is required as recommended by the GALL Report. However, although not required, the applicant has elected to provide further evaluation for each of the eight aging effects. The staff finds this additional evaluation acceptable.The staff's review of the eight aging effects follows.
  (1)Cracking, Loss of Bond, and Loss of Material (Spalling, Scaling) Due to Corrosion ofEmbedded Steel for Groups 1-5, 7, 9 StructuresThe staff reviewed item 1 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LRSection 3.5.2.2.2.1.The applicant stated in the LRA this aging effect is not applicable to VYNPS. The agingmechanisms associated with cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel are applicable only to below-grade concrete/grout structures owing to the slightly acidic pH of groundwater. The below-grade environment for VYNPS is not aggressive and concrete is designed in accordance with specification ACI 318-63, "Building Code Requirements for Reinforced Concrete," which results in low permeability and resistance to aggressive chemical solutions by providing a high cement, low water/cement ratio (between 0.44 and 0.60), proper curing and adequate air content between 3 percent and 5 percent.
Therefore, cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel are not aging effects requiring management for VYNPS Groups 1-5, 7, 9
 
structures. The staff finds that the cracking, loss of bond, and loss of material (spalling, scaling) due tocorrosion of embedded steel for Groups 1-5, 7, 9 structures are not plausible aging effects at VYNPS due to the lack of aggressive groundwater and the concrete being designed in accordance with ACI 318-63 with a high cement, low water/cement ratio and adequate air content between 3 and 5 percent. Since corrosion of the embedded steel could become significant if exposed to an aggressive environment, components in these groups are included in the Structures Monitoring Program.The staff finds that, based on the programs identified above, the applicant has met the criteria ofSRP-LR Section 3.5.2.2.2.1 for further evaluation.  (2)Increase in Porosity and Permeability, Cracking, Loss of Material (Spalling, Scaling) Dueto Aggressive Chemical Attack for Groups 1-5, 7, 9 StructuresThe staff reviewed item 2 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LRSection 3.5.2.2.2.1.The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Aggressivechemical attack becomes significant to concrete exposed to an aggressive environment.
Resistance to mild acid attack is enhanced by using a dense concrete with low permeability and a low water-to-cement ratio of less than 0.50. These groups of structures at VYNPS use a dense, low permeable concrete with an average water-to-cement ratio of 0.48, which provides 3-443an acceptable degree of protection against aggressive chemical attack. Water chemical analysisresults confirm that the site groundwater is considered to be non-aggressive. VYNPS concrete is constructed in accordance with the recommendations in ACI 201.2R-77 for durability. VYNPS below-grade environment is not aggressive. Therefore, increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack are AERMs requiring management for VYNPS Groups 1-5, 7, 9 concrete structures.The staff finds that the increase in porosity and permeability, cracking, loss of material (spalling,scaling) due to aggressive chemical attack for Groups 1-5, 7, 9 structures are not plausible aging effects at VYNPS due to the lack of aggressive groundwater and the concrete being constructed in accordance with the recommendations in ACI 201.2R-77 for durability with a high cement, low water/cement ratio. Since aggressive chemical attack could become significant for concrete exposed to an aggressive environment, components in these groups are included in the Structures Monitoring Program. The staff finds that, based on the programs identified above, the applicant has met the criteria ofSRP-LR Section 3.5.2.2.2.1 for further evaluation.  (3) Loss of Material Due to Corrosion for Groups 1-5, 7, 8 Structures The staff reviewed item 3 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LRSection 3.5.2.2.2.1.The applicant stated, in the LRA, that this aging effect is applicable to VYNPS. The StructuresMonitoring Program will be used to manage this AERM for VYNPS Groups 1-5, 7, 8 structures.The staff finds that the loss of material due to corrosion for Groups 1-5, 7, 8 structures is anaging effect which will be managed by the applicant's Structures Monitoring Program.The staff finds that, based on the program identified above, the applicant has met the criteria ofSRP-LR Section 3.5.2.2.2.1 for further evaluation.  (4)Loss of Material (Spalling, Scaling) and Cracking Due to Freeze-Thaw for Groups 1-3, 5,7-9 Structures The staff reviewed item 4 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LRSection 3.5.2.2.2.1.The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Aggregateswere in accordance with specifications and materials conforming to ACI and ASTM standards.
VYNPS structures are constructed of a dense, durable mixture of sound coarse aggregate, fine aggregate, cement, water, and admixture. Water/cement ratios are within the limits in accordance with ACI 318-63, and air entrainment percentages were within the range prescribed in the GALL Report. Therefore, loss of material (spalling, scaling) and cracking due to freeze thaw are not AERMs for VYNPS Groups 1-3, 5, 7-9 structures.
3-444The staff finds that the loss of material (spalling, scaling) and cracking due to freeze-thaw forGroups 1-3, 5, 7-9 structures are not plausible aging effects at VYNPS due to concrete being constructed in accordance with ACI and ASTM standards with a high cement, low water/cement ratio. Since evaluation is needed for plants that are located in moderate to severe weathering conditions, components in these groups are included within the Structures Monitoring Program.In the discussion column of LRA Table 3.5.1, Item 3.5.1-26, the applicant stated that freeze-thawis not an applicable aging mechanism for these groups of structures at VYNPS. During the audit and review, the staff asked the applicant to provide documentation showing the weathering conditions (weathering index) for VYNPS and the specification requiring concrete to have an air content of 3 percent to 6 percent and water to cement ratio of 0.35 to 0.45.During interviews with the applicant's technical personnel, the applicant's staff stated thatVYNPS inaccessible and accessible concrete areas are designed in accordance with specification ACI 318-63.The applicant states that VYNPS concrete also meets recommendations of later guideACI 201.2R-77, since both documents use the same ASTM standards for selection, application and testing of concrete. VYNPS concrete was provided with air content between 3 percent and 5 percent and a water/cement ration between 0.44 and 0.60, as documented in the Audit and Review Report. VYNPS is located in a severe weathering region (weathering index greater than100 day-inch/yr) as indicated in ASTM C33, FIG. 1. Although the water/cement ratio fallsoutside the listed range of 0.35 to 0.45, given all the parameters associated with a concrete mix design VYNPS concrete meets the quality requirements of ACI to ensure acceptable concrete is obtained. Nonetheless concrete be will managed in accordance with the AMP s identified in the LRA 3.5.2 -1 through 3.5.2-6. tables.The staff finds that, based on the programs identified above, the applicant has met the criteria ofSRP-LR Section 3.5.2.2.2.1.    (5)Cracking Due to Expansion and Reaction with Aggregates for Groups 1-5, 7-9 Structures The staff reviewed item 5 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1.The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Aggregateswere selected locally and were in accordance with specifications and materials conforming to ACI and ASTM standards at the time of construction, which are in accordance with the recommendations in ACI 201.2R-77 for concrete durability. VYNPS structures are constructed of a dense, durable mixture of sound coarse aggregate, fine aggregate, cement, water, and admixture. Water/cement ratios are within the limits specified in ACI 318-63, and air entrainment percentages were within the range prescribed in the GALL Report. Therefore, cracking due to expansion and reaction with aggregates for Groups 1-3, 5, 7-9 structures is not an AERM for VYNPS concrete.
3-445The staff finds through discussions with the applicant's technical personnel that cracking due toexpansion and reaction with aggregates for Groups 1-5, 7-9 structures are not plausible aging effects at VYNPS due to concrete being constructed in accordance with ACI and ASTM standards with a high cement, low water/cement ratio. Since evaluation is needed for concrete not constructed in accordance with ACI 201.2R-77, components in this group are included within the Structures Monitoring Program.During the audit and review, the staffed asked the applicant to provide documentation showingthat inaccessible areas concrete was constructed in accordance with the recommendations in ACI 201.2R-77.During interviews with the applicant's technical personnel, the applicant's staff stated that forconstruction of concrete, VYNPS site specification, as documented in the Audit and ReviewReport, identifies the same ASTM standards for achieving durable concrete as those specified in ACI 201.2R-77.The staff finds that, based on the programs identified above, the applicant has met the criteria ofSRP-LR Section 3.5.2.2.2.1 for further evaluation.    (6)Cracks and Distortion Due to Increased Stress Levels from Settlement for Groups 1-3,5-9 Structures The staff reviewed item 6 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LRSection 3.5.2.2.2.1.The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Class 1structures at VYNPS are founded on sound bedrock or supported by steel pilings which prevent significant settlement. Therefore, cracks and distortion due to increased stress levels from settlement are not aging effects requiring management for VYNPS Groups 1-3, 5-9 structures. The staff finds that the cracks and distortion due to increased stress levels from settlement forGroups 1-3, 5-9 structures not plausible aging effects due to the nonexistence of these aging mechanisms. The VYNPS Class 1 structures are founded on sound bedrock or supported by steel pilings which prevents significant settlement. The staff finds that these aging effects are not applicable to VYNPS Class 1 structures. Since evaluation to ensure proper functioning of a de-watering is needed if a de-watering system is relied upon to control settlement through the period of extended operation, components in this group are included within the Structures Monitoring Program.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.  (7)Reduction in Foundation Strength, Cracking, Differential Settlement Due to Erosion ofPorous Concrete Subfoundation for Groups 1-3, 5-9 StructuresThe staff reviewed item 7 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LRSection 3.5.2.2.2.1.
3-446The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Structures atVYNPS are not constructed of porous concrete. Concrete was provided in accordance with ACI 318-63 requirements resulting in dense, well-cured, high-strength concrete with low-permeability. Therefore, reduction in foundation strength, cracking, differential settlement due to erosion of porous concrete subfoundation are not aging effects requiring management for VYNPS Groups 1-3, 5-9 structures. The staff finds through discussions with the applicant's technical personnel that the reduction infoundation strength, cracking, differential settlement due to erosion of porous concrete subfoundation for Groups 1-3, 5-9 structures are not plausible aging effects due to the nonexistence of these aging mechanisms. Since there are no porous concrete subfoundations of concern below these structures, the staff finds that these aging effects are not applicable to VYNPS Groups 1-3 and 5-9 structures.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.  (8)Lock Up Due to Wear for Lubrite Radial Beam Seats in BWR Drywell and Other SlidingSupport SurfacesThe staff reviewed item 8 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LRSection 3.5.2.2.2.1.The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Owing to thewear-resistant material used, the low frequency (number of times) of movement, and the slowmovement between sliding surfaces, lock-up due to wear is not considered to be an AERM at
 
VYNPS.The staff finds through discussions with the applicant's technical personnel that the lock up dueto wear for Lubrite radial beam seats in BWR drywell and other sliding support surfaces are not plausible aging effects at VYNPS due to the wear-resistant material used, the low frequency(number of times) of movement, and the slow movement between sliding surfaces. Since the absence of this aging effects needs to be confirmed, components in this group are included within the Structures Monitoring Program and Inservice Inspection (IWF) Program.The staff finds that, based on the programs identified above, the applicant has met the criteria ofSRP-LR Section 3.5.2.2.2.1. Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.5.2.2.2.1 criteria. For those line items that apply to LRA Section 3.5.2.2.2.1, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-447Aging Management of Inaccessible Areas. The staff reviewed LRA Section 3.5.2.2.2.2 againstthe following SRP-LR Section 3.5.2.2.2.2 criteria:  (1)LRA Section 3.5.2.2.2.2 addresses the same accessible area discussion in SERSection 3.5.2.2.2.1 item 4 above for inaccessible areas.SRP-LR Section 3.5.2.2.2.2 states that loss of material (spalling, scaling) and crackingdue to freeze-thaw may occur in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures. The GALL Report recommends further evaluation of this aging effect for inaccessible areas of these groups of structures for plants located in moderate to severe weather conditions.The staff's evaluation remains the same as provided in SER Section 3.5.2.2.2.1 item 4for inaccessible areas.  (2)LRA Section 3.5.2.2.2.2 addresses the same accessible area discussion in SERSection 3.5.2.2.2.1 item 5 above for inaccessible areas.SRP-LR Section 3.5.2.2.2.2 states that cracking due to expansion and reaction withaggregates may occur in below-grade inaccessible concrete areas for Groups 1-5 and 7-9 structures. The GALL Report recommends further evaluation of inaccessible areas of these groups of structures if concrete was not constructed in accordance with ACI 201.2R-77 recommendations.The staff's evaluation remains the same as provided in SER Section 3.5.2.2.2.1 item 5for inaccessible areas.  (3)LRA Section 3.5.2.2.2.2 addresses the same accessible area discussion in SERSection 3.5.2.2.2.1 item 7 above for Groups 1-3, 5 and 7-9 inaccessible areas.SRP-LR Section 3.5.2.2.2.2 states that cracks and distortion due to increased stresslevels from settlement and reduction of foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundations may occur in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures. The existing program relies on structures monitoring to manage these aging effects. Some plants may rely on de-watering systems to lower site ground water level. If the plant's CLB credits a de-watering system, the GALL Report recommends verification of the system's continued functionality during the period of extended operation. The GALL Report recommends no further evaluation if this activity is included in the scope of the applicant's structures monitoring program.The staff's evaluation remains the same as provided in SER Section 3.5.2.2.2.1 item 7 forinaccessible areas.
3-448  (4)LRA Section 3.5.2.2.2.2 addresses the aging management of inaccessible areas, theseaging effects are not applicable to VYNPS.SRP-LR Section 3.5.2.2.2.2 states that increase in porosity and permeability, cracking,and loss of material (spalling, scaling) due to aggressive chemical attack and cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel may occur in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures. The GALL Report recommends further evaluation of plant-specific programs to manage these aging effects in inaccessible areas of these groups of structures in aggressive environments.The staff's evaluation of the above aging effect is provided below.  (5)LRA Section 3.5.2.2.2.2 addresses the aging management of inaccessible areas, theseaging effects are not applicable to VYNPS.SRP-LR Section 3.5.2.2.2.2 states that increases in porosity and permeability and loss ofstrength due to leaching of calcium hydroxide may occur in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures. The GALL Report recommends further evaluation of this aging effect for inaccessible areas of these groups of structures for concrete not constructed in accordance with ACI 201.2R-77 recommendations. LRA Section 3.5.2.2.2.2 addresses both items 4 and 5 in SRP-LR Section 3.5.2.2.2.2.The applicant stated in the LRA, that VYNPS concrete for Group 1-3, 5 and 7-9inaccessible concrete areas was provided in accordance with specification ACI 318-63, Building Code Requirements for Reinforced Concrete, which requires the following, resulting in low permeability and resistance to aggressive chemical solution.
* high cement content
* low water permeability
* proper curing
* adequate air entrainmentThe applicant also stated that VYNPS concrete also meets recommendations of later ACI guideACI 201.2R-77, since both documents use the same ASTM standards for selection, application and testing of concrete. Inspections of accessible concrete have not revealed degradation related to corrosion of embedded steel. VYNPS below-grade environment is not aggressive (pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1,500 ppm). Therefore, corrosion of embedded steel is not an AERM for VYNPS concrete.The staff finds through discussions with the applicant's technical personnel that the agingmanagement of inaccessible areas due to aggressive chemical attack for Groups 1-5, 7 and 9 structures are not plausible aging effects at VYNPS due to the lack of aggressive groundwater and the concrete being constructed in accordance with the recommendations in ACI 201.2R-77 for durability with a high cement, low water/cement ratio. The applicant will perform opportunistic inspections of below-grade concrete in accordance with the Buried Piping Inspection Program and perform sampling monitoring of groundwater for aggressiveness in accordance with the Structures Monitoring Program.
3-449Based on the programs identified above, the applicant has met the staff concludes that theapplicant's programs meet criteria of SRP-LR Section 3.5.2.2.2.2 criteria.
For those line items that apply to LRA Section 3.5.2.2.2.2, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. Thestaff reviewed LRA Section 3.5.2.2.2.3 against the criteria in SRP-LR Section 3.5.2.2.2.3.In LRA Section 3.5.2.2.2.3, the applicant stated that for the reduction of strength and modulus ofconcrete structures due to elevated temperature, this aging effect is not applicable to VYNPS.SRP-LR Section 3.5.2.2.2.3 states that reduction of strength and modulus of concrete due toelevated temperatures may occur in PWR and BWR Groups 1-5 concrete structures. For concrete elements that exceed specified temperature limits, further evaluations are recommended. Appendix A to ACI 349-85 specifies the concrete temperature limits for normal operation or any other long-term period. Temperatures shall not exceed 150 F except for localareas allowed to have temperatures not to exceed 200 F. The GALL Report recommendsfurther evaluation of a plant-specific program if any portion of the safety-related and other concrete structures exceeds specified temperature limits (i.e., general area temperature greater than 66 C (150 F) and local area temperature greater than 93 C (200 F)).The applicant stated, in the LRA, that for the reduction of strength and modulus of concretestructures due to elevated temperature, this aging effect is not applicable to VYNPS. Group 1-5 concrete elements do not exceed the temperature limits associated with aging degradation due to elevated temperature. Therefore, reduction of strength and modulus of concrete due to elevated temperatures is not an AERM for VYNPS. The applicant also stated, during the audit and review, that the aging effects due to elevatedtemperature are not expected at VYNPS for the concrete associated with Group 1-5 structures since general areas temperatures within the primary containment do not exceed 150F and localarea temperatures do not exceed 200F. The staff agrees with the applicant that these agingeffects are not applicable to the VYNPS Group 1-5 structures concrete.During the audit and review, the staff asked the applicant to provide the maximum temperaturesthat concrete experiences in Group 1 through 5 structures. The applicant's staff stated that the VYNPS concrete is expected to experience average general area temperature of 150F andlocal area maximum temperature less than 200F. The drywell cooling system recirculates thedrywell atmosphere through heat exchangers to maintain ambient temperature in the drywell between 135F and 165F (average 150F). (Reference UFSAR Sections 5.2.3.2 and 10.12.3).The concrete around piping penetrations for high temperature lines, such as the steam lines and other reactor system lines is protected by piping insulation and air gaps.The staff finds that the reduction of strength and modulus of concrete structures due to elevatedtemperatures are not plausible aging effects due to the nonexistence of these aging mechanisms. A plant-specific AMP will be evaluated if temperature limits are exceeded.
3-450The staff finds that the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.3.For those line items that apply to LRA Section 3.5.2.2.2.3, the staff finds that the LRA isconsistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).Aging Management of Inaccessible Areas for Group 6 Structures. The staff reviewed LRASection 3.5.2.2.2.4 against the following SRP-LR Section 3.5.2.2.2.4 criteria:  (1)In LRA Section 3.5.2.2.2.4, the applicant stated that for the increase in porosity andpermeability, cracking, loss of material (spalling, scaling)/aggressive chemical attack; and cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel in below-grade inaccessible concrete areas of Group 6 structures, this aging effect is not applicable to VYNPS.SRP-LR Section 3.5.2.2.2.4 states that increase in porosity and permeability, cracking,loss of material (spalling, scaling)/aggressive chemical attack and cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel may occur in below-grade inaccessible concrete areas of Group 6 structures. The GALL Report recommends further evaluation of plant-specific programs to manage these aging effects in inaccessible areas in aggressive environments.The applicant stated, in the LRA, that for the increase in porosity and permeability,cracking, loss of material (spalling, scaling)/aggressive chemical attack; and cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel in below-grade inaccessible concrete areas of Group 6 structures, this aging effect is not applicable to VYNPS. Below-grade exterior reinforced concrete at VYNPS is not exposed to an aggressive environment (pH less than 5.5), or to chloride or sulfate solutions beyond defined limits (greater than 500 ppm chloride, or greater than 1500 ppm sulfate).
Therefore, increase in porosity and permeability, cracking, loss of material (spalling, scaling)/aggressive chemical attack; and cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel are not aging effects requiring management for below-grade inaccessible concrete areas of VYNPS Group 6 structures. The staff finds that the increase in porosity and permeability, cracking, loss of material(spalling, scaling)/aggressive chemical attack; and cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel in below-grade inaccessible concrete areas of Group 6 structures are not plausible aging effects at VYNPS due to the lack of aggressive groundwater and the concrete being constructed in accordance with the recommendations in ACI 201.2R-77 for durability with a high cement, low water/cement ratio. The applicant will perform opportunistic inspections of below-grade concrete in accordance with the Buried Piping Inspection Program and perform sample monitoring of groundwater for aggressiveness in accordance with the Structures Monitoring Program.
3-451During the audit and review, the staff noted that in the discussion column of LRATable 3.5.1, Item 3.5.1-34, the applicant did not make reference to LRA Section 3.5.2.2.2.4, item 1 for further evaluation. The applicant was asked to explain why this link was not made to the further evaluation section. The applicant's staff stated that SRP-LR, Item 3.5.1-34 indicates that further evaluation is necessary only for aggressiveenvironments. No reference was provided to further evaluation in LRA Section 3.5.2.2.2.4, item 1 since the VYNPS environment is not aggressive as noted in LRA Table 3.5.1, item 3.5.1-34, in accordance with the discussion column. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated thatLRA Table 3.5.1, Line Item 3.5.1-34 discussion column is revised to add "See Section 3.5.2.2.2.4 (1)."The staff finds that, based on the programs identified above, the applicant has met thecriteria of SRP-LR Section 3.5.2.2.2.4 for further evaluation.  (2)In LRA Section 3.5.2.2.2.4, the applicant stated that for the loss of material (spalling,scaling) and cracking due to freeze-thaw in below-grade inaccessible concrete areas of Group 6 structures, this aging effect is not applicable to VYNPS.SRP-LR Section 3.5.2.2.2.4 states that loss of material (spalling, scaling) and crackingdue to freeze-thaw may occur in below-grade inaccessible concrete areas of Group 6 structures. The GALL Report recommends further evaluation of this aging effect for inaccessible areas for plants located in moderate to severe weather conditions.The applicant stated, in the LRA, that for the loss of material (spalling, scaling) andcracking due to freeze-thaw in below-grade inaccessible concrete areas of Group 6 structures, this aging effect is not applicable to VYNPS. Aggregates were selected locally and were in accordance with specifications and materials conforming to ACI and ASTM standards at the time of construction. VYNPS structures are constructed of a dense, durable mixture of sound coarse aggregate, fine aggregate, cement, water, and admixture. Water/cement ratios are within the limits provided in ACI 318-63, and air entrainment percentages were within the range prescribed in the GALL Report.
Therefore, loss of material (spalling, scaling) and cracking due to freeze thaw are not aging effects requiring management for VYNPS Group 6 structures below-grade. The staff finds that the loss of material (spalling, scaling) and cracking due to freeze-thawin below-grade inaccessible concrete areas of Group 6 structures are not plausible aging effects at VYNPS due to concrete being constructed in accordance with ACI and ASTM standards with a high cement, low water/cement ratio. Since evaluation is needed for plants that are located in moderate to severe weathering conditions, components in these groups are included within the Structures Monitoring Program.During the audit and review, the staff noted that in the discussion column of LRATable 3.5.1, Item 3.5.1-35, the applicant did not make reference to LRA Section 3.5.2.2.2.4 item 2 for further evaluation. The applicant was asked to explain why this link was not made to the further evaluation section. Also, the applicant was asked to 3-452provide a copy of ACI 301 as listed in accordance with the discussion column. Theapplicant's staff stated that due to an administrative error, the reference to ACI should have been ACI 318-63 and not ACI 301. The applicant stated that the LRA Table 3.5.1, Item 3.5.1-35 discussion column will be revised to refer to ACI 318-63. For clarification, a reference to (LRA Section 3.5.2.2.2.4.2) will also be added to the discussion column. In a letter dated July 14, 2006, the applicant amended its LRA. The applicant stated thatthe LRA Table 3.5.1-35 discussion column is revised to replace ACI 301 with ACI 18-63 and add "See Section 3.5.2.2.2.4 (2)" at the end of the existing discussion column.The staff finds that, based on the programs identified above, the applicant has met thecriteria of SRP-LR Section 3.5.2.2.2.4.    (3)In LRA Section 3.5.2.2.2.4, the applicant stated that for cracking due to expansion andreaction with aggregates, increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide in below-grade inaccessible concrete areas of Group 6 structures, this aging effect is not applicable to VYNPS.SRP-LR Section 3.5.2.2.2.4 states that cracking due to expansion and reaction withaggregates and increased porosity and permeability and loss of strength due to leaching of calcium hydroxide may occur in below-grade inaccessible reinforced concrete areas of Group 6 structures. The GALL Report recommends further evaluation of inaccessible areas for concrete not constructed in accordance within ACI 201.2R-77 recommendations.The applicant stated, in the LRA, that for cracking due to expansion and reaction withaggregates, increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide in below-grade inaccessible concrete areas of Group 6 structures, this aging effect is not applicable to VYNPS. Aggregates were selected locally and were in accordance with specifications and materials conforming to ACI and ASTM standards at the time of construction, which are in accordance with the recommendations in ACI 201.2R-77 for concrete durability. VYNPS structures are constructed of a dense, durable mixture of sound coarse aggregate, fine aggregate, cement, water, and admixture. Water/cement ratios are within the limits provided in ACI 318-63, and air entrainment percentages were within the range prescribed in the GALL Report. VYNPS below-grade environment is not aggressive (pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1,500 ppm). Therefore, cracking due to expansion and reaction with aggregates, increase in porosity and permeability due to leaching of calcium hydroxide in below grade inaccessible concrete areas of Group 6 structures is not an aging mechanism for VYNPS concrete. The staff finds that cracking due to expansion and reaction with aggregates, increase inporosity and permeability, and loss of strength due to leaching of calcium hydroxide in below-grade inaccessible concrete areas of Group 6 structures are not plausible aging effects at VYNPS due to concrete being constructed in accordance with ACI and ASTM 3-453standards with a high cement, low water/cement ratio and the below grade environmentnon-aggressive. Since evaluation is needed for concrete not constructed in accordance with ACI 201.2R-77, components in this group are included within the Structures Monitoring Program.During the audit and review, the staff noted that in the discussion column of LRATable 3.5.1, Item 3.5.1-36, the applicant did not make reference to LRA Section 3.5.2.2.2.4 item 3 for further evaluation. The applicant was asked to explain why this link is not made to the further evaluation section. Also, the statement: "See Section 3.5.2.2.2.1.5 for additional discussion" needs further clarification that this section is for Groups 1-5, 7-9, however it would apply to accessible Group 6 concrete. Further the applicant was asked to explain why LRA Section 3.5.2.2.2.4 item 3 lists cracking of concrete due to SCC.In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated thatthe LRA Table 3.5.1, Item 3.5.1-36, discussion column is revised to read as follows: Reaction with aggregates is not an applicable aging mechanism for VYNPSconcrete components. See Section 3.5.2.2.2.1(5) (although for Groups 1-5, 7, 9 this discussion is also applicable for Group 6). See Section 3.5.2.2.2.4(3) additional discussion. Nonetheless, the Structures Monitoring Program will confirm the absence of aging effects requiring management for VYNPS Group 6 concrete components.Also, to correct an administrative error, the heading of LRA Section 3.5.2.2.2.4(3) isrevised to begin with "Cracking Due to Expansion and Reaction with Aggregates." The term stress corrosion cracking is deleted from the heading as it does not apply to this
 
section.During the audit and review, the staff noted that in the discussion column of LRATable 3.5.1, Item 3.5.1-37, the applicant stated not applicable and makes reference to Section 3.5.2.2.2.4 item 3. Section 3.5.2.2.2.4 item 3. This item discusses inaccessible areas only. The staff asked the applicant to explain why the discussion column for LRA Table 3.5.1, Item 3.5.1-37 did not state: "Nonetheless, the Structures Monitoring Program will confirm the absence of aging effects requiring management for VYNPS Group 6 concrete components." This would apply to above grade concrete, like in LRA Table 3.5.1, Item 3.5.1-36 for accessible concrete.In a letter dated July 14, 2006, the applicant its amended the LRA. The applicant statedthat the LRA Table 3.5.1, Item 3.5.1-37, discussion column is revised to state the following: "Not applicable. Nonetheless the Structures Monitoring Programwill confirm the absence of aging effects requiring management for VYNPS Group 6 concrete components. See Section 3.5.2.2.2.4(3)."
3-454Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.5.2.2.2.4.criteria.For those line items that apply to LRA Section 3.5.2.2.2.4, the staff finds that the LRA isconsistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).Cracking Due to Stress Corrosion Cracking and Loss of Material Due to Pitting and CreviceCorrosion. The staff reviewed LRA Section 3.5.2.2.2.5 against the criteria in SRP-LRSection 3.5.2.2.2.5.In LRA Section 3.5.2.2.2.5, the applicant stated that for the cracking due to SCC and loss ofmaterial due to pitting and crevice corrosion, this aging effect is not applicable to VYNPS. No tanks with stainless steel liners are included in the structural AMRs. Tanks subject to an AMR are evaluated with their respective mechanical systems. SRP-LR Section 3.5.2.2.2.5 states that cracking due to SCC and loss of material due to pittingand crevice corrosion may occur in Groups 7 and 8 stainless steel tank liners exposed to standing water. The GALL Report recommends further evaluation of plant-specific programs to manage these aging effects.The staff finds that the cracking due to SCC and loss of material due to pitting and crevicecorrosion are not aging effects requiring management at VYNPS since there are no tanks with stainless steel liners included in the structural AMRs. Tanks subject to an AMR are evaluated with their respective mechanical systems.On the basis that VYNPS does not have any components from this group, the staff finds that thisaging effect is not applicable to VYNPS.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.5.2.2.2.5 criteria. For those line items that apply to LRA Section 3.5.2.2.2.5, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).Aging of Supports Not Covered by the Structures Monitoring Program. The staff reviewed LRASection 3.5.2.2.2.6 against the criteria in SRP-LR Section 3.5.2.2.2.6.In LRA Section 3.5.2.2.2.6, the applicant addressed aging of supports not covered by theStructures Monitoring Program.SRP-LR Section 3.5.2.2.2.6 states that the GALL Report recommends further evaluation ofcertain component support-aging effect combinations not covered by structures monitoring programs, including: (1) loss of material due to general and pitting corrosion for Groups B2-B5 supports, (2) reduction in concrete anchor capacity due to degradation of the surrounding concrete for Groups B1-B5 supports, and (3) reduction/loss of isolation function due to 3-455degradation of vibration isolation elements for Group B4 supports. Further evaluation isnecessary only for structure-aging effect combinations not covered by the applicant's structures monitoring program.The applicant stated, in the LRA, that the GALL Report recommends further evaluation of certaincomponent support/aging effect combinations if they are not covered by the applicant's Structure Monitoring Program. Components supports at VYNPS are included in the Structures Monitoring Program for Groups B2 through B5 and Inservice Inspection (IWF) Program for Group B1.  (1)Reduction in concrete anchor capacity due to degradation of the surrounding concrete forGroups B1 through B5 supportsVYNPS concrete anchors and surrounding concrete are included in the StructuresMonitoring Program (Groups B2 through B5) and Inservice Inspection (IWF) Program (Group B1).  (2)Loss of material due to general and pitting corrosion, for Groups B2-B5 supportsLoss of material due to corrosion of steel support components is an AERM at VYNPS.This aging effect is managed by the Structures Monitoring Program.  (3)Reduction/loss of isolation function due to degradation of vibration isolation elements forGroup B4 supportsThe VYNPS AMR did not identify any component support structure/aging effectcombination corresponding to the GALL Report, Volume 2, Item III.B4-12.The staff finds that the applicant has included the above aging effect/mechanism combinationswithin the scope of its Structures Monitoring Program or Inservice Inspection (IWF) Program and agreed that no further evaluation is required. The staff finds that reduction/loss of isolation function due to degradation of vibration isolation elements for Group B4 supports is not an AERM at VYNPS since there are no vibration isolation components within the scope of license renewal. The staff reviewed the applicant's Structures Monitoring Program and Inservice Inspection (IWF) Program and its evaluations are documented in SER Sections 3.0.3.2.17 and 3.0.3.3.3, respectively. The staff finds the applicant's Structures Monitoring Program and Inservice Inspection (IWF) Program acceptable for managing the above aging effect/mechanism combinations of component supports for the GALL Report component support Groups B1 through B5, as those combinations are applicable.During the audit and review, the staff noted that in the discussion column of LRA Table 3.5.1,Item 3.5.1-40, the applicant stated:Plant experience has not identified reduction in concrete anchor capacity or otherconcrete aging mechanisms. Nonetheless, the Structures Monitoring Program will confirm absence of aging effects requiring management for VYNPS concrete components.
3-456The staff was not able to find an AMR line item in Table 2 for this component (Building concreteat locations of expansion and grouted anchors; grout pads for support base plates). During the audit and review, the applicant was asked to provide the Table 2 number, LRA page number, and component for where this AMR line item is evaluated and shown. The applicant stated that building concrete at locations of expansion and grouted anchors; grout pads for support base plates are shown as "foundation" and "Reactor vessel support pedestal" in LRA Table 3.5.2-1 (page 3.5-54), "foundation" in LRA Tables 3.5.2-2 through 3.5.2-5 (pages 3.5-58, 3.5-60, 3.5-62, and 3.5-66), and as "Equipment pads/foundations" in LRA Table 3.5.2-6 (page 3.5-78). Further evaluation is provided in LRA Section 3.5.2.2.2.6.1 (page 3.5-14).In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRATable 3.5.1, Item 3.5.1-40 discussion column is revised to add "See Section 3.5.2.2.2.6(1)."During the audit and review, the staff noted that in the discussion column of LRA Table 3.5.1,Item 3.5.1-41, the applicant stated:No vibration isolation elements at VYNPS are in-scope and subject to an AMR. During the audit and review, the applicant was asked to explain the lack of vibration isolationelements for HVAC system components, the EDG and miscellaneous mechanical equipment.
The applicant's staff stated that LRA Table 3.5.1 relates only to structures and structural supports. Thus, the statement that no vibration isolation elements are in-scope and subject to an AMR applies only to structural vibration isolation elements. Vibration isolation elements formechanical system components are subject to an AMR. For example, LRA Table 3.3.2-4 contains expansion joint in the EDG system and LRA Table 3.3.2-10 contains duct flexible connections and expansion joints in heating, ventilation, and air conditioning systems.The staff reviewed the applicant response and asked a followup question. The applicant wasasked to verify that there are no non-metalic (rubber) vibration isolation elements used to structurally support the EDG, HVAC system equipment, and miscellaneous mechanical equipment and that all vibration isolation to systems attached to these components is by expansion joints and flexible connections. The applicant's staff stated that as stated in LRA Table 3.5.1, Item 3.5.1-41, there are no non-metallic (rubber) vibration isolation elements used to structurally support the EDG, HVAC system equipment, and miscellaneous mechanical equipment that is within the scope of license renewal. Vibration isolation to systems attached to these components is by expansion joints and flexible connections.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.5.2.2.2.6. criteria.For those line items that apply to LRA Section 3.5.2.2.2.6, the staff finds that the LRA isconsistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-457Cumulative Fatigue Damage Due to Cyclic Loading. LRA Section 3.5.2.2.2.7 states that fatigueof component support members, anchor bolts, and welds for Groups B1.1, B1.2, and B1.3 component supports is a TLAA, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.The applicant stated, in LRA Section 3.5.2.2.2.7, that for component support members, anchorbolts, and welds for Groups B1.1, B1.2, and B1.3, this aging effect is not applicable to VYNPS.
During the process of identifying TLAAs in the VYNPS CLB , no fatigue analyses were identified for these components. The staff finds that there are no CLB fatigue analyses for component support members, anchorbolts, and welds for Groups B1.1, B1.2, and B1.3 and therefore cumulative fatigue damage can not be evaluated as an aging effect for these components.On the basis that VYNPS does not have any components from this group with fatigue analyses,the staff finds that this aging effect is not applicable to VYNPS.3.5.2.2.3  Quality Assurance for Aging Management of Nonsafety-Related Components SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.
 
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff finds that the applicant adequately addressed the issues that were further evaluated. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.5.2.3  AMR Results Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.5.2-1 through 3.5.2-6, thestaff reviewed additional details of the AMR results for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report.In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant indicated, via notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information about how it will manage the aging effects. Specifically, note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.
3-458Staff Evaluation. For component type, material, and environment combinations not evaluated inthe GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff's evaluation is documented in the following sections.3.5.2.3.1  Primary Containment Summary of Aging Management Evaluation-LRA Table 3.5.2-1 The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for theprimary containment component groups.The staff finds that all AMR evaluation results in LRA Table 3.5.2-1 are consistent with the GALLReport, or if not consistent, previously discussed in SER Sections 3.5.2.1 or 3.5.2.2, respectively.The staff's review of the applicant's AMR evaluations identified areas in which additionalinformation was necessary to complete the review. The staff identified ten RAIs (3.5-1 through 3.5-10), which were sent them to the applicant. During a teleconference, the applicant indicated that five of the (RAIs 3.5-1, 3.5-3, 3.5-4, 3.5-8, and 3.5-10) had been resolved with the NRC audit team and evidence of their resolutions was provided. The applicant responded to RAIs 3.5-2, 3.5-5, 3.5-6, 3.5-7, and 3.5-9 as discussed below.In RAI 3.5-2 dated September 28, 2006, the staff stated that LRA Table 3.5.2-1 does not listdowncomers as a component; however, downcomers are listed in LRA Table 3.5.1 tem 3.5.1-13.
The staff requested that the applicant explain why there is neither an AMP nor an AMR provided for downcomers in LRA Table 3.5.2-1."In its response dated October 31, 2006, the applicant stated that "downcomers are included inLRA Table 3.5.2-1, line item for the "Drywell to torus vent system," with the Containment Inservice Inspection Program and the Containment Leak Rate Program." Based on its review, the staff finds the applicant's response to RAI 3.5-2 acceptable because theapplicant provided proper AMPs for downcomers. The staff's concern described in RAI 3.5-2 is resolved.RAI 3.5-5 dated September 16, 2006, the staff stated that LRA Section B.1.15 for InserviceInspection Program, states that "for containment inservice inspection, including applicable relief requests, general visual and detailed visual examinations are used in addition to visual testingexaminations, in accordance with10 CFR 50.55a." The staff requested that the applicant describe the difference between the general visual, detailed visual, and visual testing examinations. The staff also requested that the applicant state the relief requests referenced in LRA Section B.1.15.
3-459In its response dated October 31, 2006, the applicant stated the following:General visual examinations are performed either directly or remotely withsufficient illumination and resolution to assess the general condition of the accessible containment surfaces (inside and outside).Detailed visual examinations are VT-1 visual examinations.
VT-1 visual examinations are conducted with sufficient illumination and access tothe containment surface to detect discontinuities and imperfections including suchconditions as cracks, wear, corrosion, erosion, or physical damage. As specified in 10 CFR 50.55a, dated September 26, 2002, VT-1 examinations will be conducted in lieu of "detailed visual" examinations of ASME Code Section XI, IWE-2310(c) for Examination Category E-C Item E4.11 (augmented examinations).VT-3 visual examinations are conducted to determine the general mechanical andstructural condition of components and their supports, such as verification of clearances, settings, physical displacements, loosed or missing parts, debris, corrosion, wear, erosion, or the loss of integrity at bolted or welded connections.
As specified in 10 CFR 50.55a, dated September 26, 2002, VT-3 inspections are conducted in lieu of the "general visual" examinations of ASME Code Section XI, IWE-2310 (b) for Examination Category E-A Items E1.12 (torus below water level) and E1.20 (vent system) and the bolting of Item E1.11 (drywell and torus above water level).Presently, no relief requests have been implemented for the VYNPS CII Program.Since ASME code relief requests have their own process under 10 CFR 50.55a, reference to relief requests in the LRA is unnecessary. References to relief requests are hereby deleted from LRA Section B.1.15.Based on its review, the staff finds the applicant's response to RAI 3.5-5 acceptable because theapplicant provided clarifications on the general visual, detailed visual, and visual testingexaminations, and stated that relief requests were deleted from LRA Section B.1.15. The staff's concern described in RAI 3.5-5 is resolved.In RAI 3.5-6 dated September 28, 2006, the staff stated that the Inservice Inspection Programand the Containment Inservice Inspection Program both state that, "The program includes augmented ultrasonic exams to measure wall thickness of the containment structure." The staff requested that the applicant explain the difference between the augmented portion of the ultrasonic exams performed in these two programs mentioned and that of the ASME Code Section XI, "Inservice Inspection Program."In its response dated October 31, 2006, the applicant stated:ASME Code, Section XI, IWE-1240 "Surface Areas Requiring AugmentedExamination" establishes criteria for determining the need for augmented examinations. This sentence was included in the description of the Inservice 3-460Inspection-Containment Inservice Inspection Program in LRA Sections A.2.1.16and B.1.15.2 to indicate that the option for augmented examination exists if necessary. There is no difference between the augmented portion of the ultrasonic exams performed in the VYNPS Containment Inservice Inspection Program mentioned and that of the ASME Code, Section XI, "Inservice Inspection Program." As of May 2006, no surface areas have been determined subject to the requirements of Paragraph IWE-1240. This determination was also provided in letter number BVY 06-043, dated May 15, 2006, from Entergy to USNRC, "Vermont Yankee Nuclear Power Station, License No. DPR-28, License Renewal Application."Based on its review, the staff finds the applicant's response to RAI 3.5-6 acceptable because theapplicant clarified that its augmented portion of the ultrasonic exams is identical to that of the ASME Code Section XI, "Inservice Inspection Program." The staff's concern described in RAI 3.5-6 is resolved.In RAI 3.5-7 dated September 28, 2006, the staff stated that LRA Section 3.5.2.2.1.1 states thatthe below-grade environment is not aggressive. The staff requested that the applicant provide actual values of pH, chlorides, and sulfates in the groundwater/soil adjacent to structures in order to verify the claim of a nonaggressive below-grade environment.In its response dated December 4, 2006, the applicant revised its response to RAI 3.5-7 datedOctober 31, 2006. The applicant stated that the December 4, 2006, response supersedes the October 31, 2006 response. In the revised response, the applicant provided sample data from April 2002 through April 2006 in the tables below.Table 3.5-2  Groundwater and Soil Sample Data from April 2002 Through April 2006 April 2002October 2002April 2003October 2003 ParameterWell 3301Well 3401Well 3301Well 3401Well 3301Well 3401Well 3301Well 3401pH6.46.06.66.06.76.06.86.8chloride (ppm)23754.3023757.3022570.30260111April 2004October 2004April 2005April 2005 ParameterWell 3301Well 3401Well 3301Well 3401Well 3301Well 3401Well 3301Well 3401pH6.46.06.76.97.17.56.67.3chloride (ppm)39911841078.132592.2388103 April 2006 ParameterWell 3301Well 3401pH6.26.6chloride (ppm)322145 3-461 The applicant stated that the sulfate values are not available because the station's indirectdischarge permit does not require measurement of sulfate levels. The applicant further stated that its commitment (Commitment #33) ensures that groundwater samples will continue to be evaluated on a periodic basis to assess the aggressiveness of groundwater on concrete. The applicant also revised Commitment #33 as follows:Included within the Structures Monitoring Program are provisions that will ensurean engineering evaluation is made on a periodic basis (at least once every five years) of groundwater samples to assess aggressiveness of groundwater to concrete. Samples will be evaluated for sulfate, pH and chloride levels.Finally, in its response, the applicant stated that the Vermont Agency of Natural Resources hasattributed the difference in chloride levels between Well 3301 and Well 3401 to road salt influence given the close proximity of Well 3301 to a roadway within the plant boundaries. Based on its review, the staff finds the applicant's response to RAI 3.5-7 acceptable because themeasured chloride values at the site are less than 500 ppm, as specified in the GALL Report, and the pH values are greater than 5.5 as required in the GALL Report. The applicant also stated the reason for not having the sulfate value, and made commitment (Commitment #33) to measure the sulfate value in the future. With this commitment, the staff's concern described in RAI 3.5-7 is resolved. In RAI 3.5-9 dated September 28, 2006, the staff requested the applicant confirm whether theaggregates used for the concrete basemat supporting the steel containment have been tested for reactivity in accordance with ASTM C-289 and C-295.In its response dated October 31, 2006, the applicant stated that "aggregates used for theconcrete foundation that support the steel containment (drywell) have been tested for reactivity in accordance with ASTM C-289 and C-295.Based on its review, the staff finds the applicant's response to RAI 3.5-9 acceptable because aggregates were tested for reactivity. The staff's concern described in RAI 3.5-9 is resolved. On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.5.2.3.2  Reactor Building Summary of Aging Management Evaluation-LRA Table 3.5.2-2 The staff reviewed LRA Table 3.5.2-2, which summarizes the results of AMR evaluations for thereactor building component groups.In LRA Table 3.5.2-2, the applicant proposed to manage loss of material of stainless materialsfor component types of spent fuel pool storage racks exposed to a fluid environment using the "Water Chemistry Control-BWR."
3-462During the audit and review, the staff noted that in LRA Table 3.5.2-2, for component spent fuelpool storage racks, material stainless steel in an exposed to fluid environment; the aging effect is loss of material. The applicant was asked to explain by what aging mechanism loss of material occurs and why the aging effect is not cracking. The applicant stated that as shown in LRA Table 3.5.2-2, the aging effect for component spent fuel pool storage racks is loss of material.
The specific aging mechanism is pitting and crevice corrosion because stainless steels are susceptible to this aging mechanism when exposed to oxygenated water in a treated water environment. Cracking is not an AERM for stainless steel in the spent fuel pool because cracking due to stress corrosion is dependent on temperature (greater than140F). The spentfuel pool treated water environment is less than 140F.The staff reviewed the applicant's Water Chemistry Control-BWR Program and its evaluation isdocumented in SER Section 3.0.3.1.11. The objective of the program is to manage aging effects caused by corrosion and cracking mechanisms. The program relies on monitoring and control of water chemistry based on BWRVIP-130. EPRI guidelines in BWRVIP-130 include recommendations for controlling water chemistry in the spent fuel pool. The staff accepted the position that loss of material exhibited by the stainless steel spent fuel pool storage racksexposed to a fluid environment is properly managed by the Water Chemistry Control-BWR Program, which through the addition of chemicals will reduce the amount of dissolved oxygen in the spent fuel pool treated water and reduce pitting and crevice corrosion of stainless steel. On the basis of its review, the staff finds the aging effect of loss of material of stainless steelmaterial exposed to a fluid environment is adequately managed using the Water Chemistry Control-BWR Program. On this basis, the staff finds that management of loss of material of stainless steel spent fuel pool storage racks in the reactor building acceptable.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.5.2.3.3  Intake Structure Summary of Aging Management Evaluation-LRA Table 3.5.2-3 The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for theintake structure component groups.The staff finds all AMR evaluation results in LRA Table 3.5.2-3 are consistent with the GALLReport, or if not consistent, previously discussed in SER Sections 3.5.2.1 or 3.5.2.2, respectively.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-4633.5.2.3.4  Process Facilities Summary of Aging Management Evaluation-LRA Table 3.5.2-4The staff reviewed LRA Table 3.5.2-4, which summarizes the results of AMR evaluations for theprocess facilities component groups.In LRA Table 3.5.2-4, the applicant proposed to manage loss of material, cracking and changein material properties of wood materials for component types cooling cell No. 2-1, cooling cell No. 2-2 and pipe supports exposed to a fluid or weather environment using the Structures Monitoring Program.The staff reviewed the applicant's Structures Monitoring Program and its evaluation isdocumented in SER Section 3.0.3.2.17. The applicant's Structures Monitoring Program is in accordance with 10 CFR 50.65 (Maintenance Rule) and based on RG  1.160 and NUMARC 93-01. These two documents provided the guidance for development of the Structures Monitoring Program to monitor the condition of structures and structural components within the scope of the Maintenance Rule, such that there is no loss of structure or structural component intended function. The staff finds that loss of material, cracking, and change in material properties exhibited by the wood for cooling cell no. 2-1, cooling cell No. 2-2 and pipe supports exposed to a fluid or weather environment are properly managed by the Structures Monitoring Program, which through an enhancement to program element Detection of Aging Effects will provide guidance for performing structural examinations of wood to identify loss of material, cracking, and change in material properties. On the basis of its review, the staff finds the aging effects of loss of material, cracking andchange in material properties of wood material exposed to a fluid or weather environment are adequately managed using the Structures Monitoring Program. On this basis, the staff finds that management of loss of material, cracking and change in material properties of wood for cooling cell No. 2-1, cooling cell No. 2-2 and pipe supports in Process Facilities acceptable.In addition, in LRA Table 3.5.2-4, the applicant proposed to manage cracking and change inmaterial properties of PVC materials for component types cooling tower fill exposed to a fluid environment using the Structures Monitoring Program.The staff reviewed the applicant's Structures Monitoring Program and its evaluation isdocumented in SER Section 3.0.3.2.17. The Structures Monitoring Program is in accordance with 10 CFR 50.65 (Maintenance Rule) and based on RG  1.160 and NUMARC 93-01. These two documents provided the guidance for development of the Structures Monitoring Program to monitor the condition of structures and structural components within the scope of the Maintenance Rule, such that there is no loss of structure or structural component intended function. The staff finds that cracking and change in material properties exhibited by the PVC for cooling tower fill exposed to a fluid environment are properly managed by the Structures Monitoring Program, which through an enhancement to program element Detection of Aging Effects will provide guidance for performing structural examinations of PVC cooling tower fill to identify cracking and change in material properties. On the basis of its review, the staff finds the aging effect of cracking and change in material properties of PVC material exposed to a fluid environment are adequately managed using the Structures Monitoring Program. On this basis, the staff finds that management of cracking and change in material properties of PVC for cooling tower fill in process facilities acceptable.
3-464On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.5.2.3.5  Yard Structures Summary of Aging Management Evaluation-LRA Table 3.5.2-5 The staff reviewed LRA Table 3.5.2-5, which summarizes the results of AMR evaluations for theyard structures component groups.The staff finds all AMR evaluation results in LRA Table 3.5.2-5 are consistent with the GALLReport, or if not consistent, previously discussed in SER Sections 3.5.2.1 or 3.5.2.2, respectively.On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.5.2.3.6  Bulk Commodities Summary of Aging Management Evaluation - LRA Table 3.5.2-6 The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for thebulk commodities component groups.In LRA Table 3.5.2-6, the applicant proposed to manage cracking and delamination separationof cera blanket materials for component types of fire stops exposed to a protected from weather environment using "Fire Protection."The staff reviewed the Fire Protection Program and its evaluation is documented in SERSection 3.0.3.2.11. The applicant's Fire Protection Program includes fire barrier inspection and diesel-driven fire pump inspection. The fire barrier inspection requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire rated doors to ensure that their operability is maintained.
The diesel-driven fire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. The staff finds that cracking and delamination separation exhibited by cera blanket materials for fire stops exposed to a protectedfrom weather environment is properly managed by the Fire Protection Program, which in accordance with program element Detection of Aging Effects will perform examinations of cera blanket fire stops to identify cracking and delamination separation. On the basis of its review, the staff finds the aging effects of cracking and delamination separation of cera blanket material exposed to a protected from weather environment are effectively managed using the Fire Protection Program. On this basis, the staff finds that management of cracking and delamination separation of cera blanket fire stops in bulk commodities is acceptable.
3-465In addition, in LRA Table 3.5.2-6, the applicant proposed to manage loss of material of cerafiberand cera blanket materials for component types of fire wrap exposed to a protected from weather environment using "Fire Protection."The staff reviewed the applicant's Fire Protection Program and its evaluation is documented inSER Section 3.0.3.2.11. The Fire Protection Program includes fire barrier inspection and diesel-driven fire pump inspection. The fire barrier inspection requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire rated doors to ensure that their operability is maintained.
The diesel-driven fire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. The staff finds that loss of material exhibited by cerafiber and cera blanket materials for fire wraps exposed to a protected from weather environment is properly managed by the Fire Protection Program, which in accordance with program element Detection of Aging Effects will perform examinations of cerafiber and cera blanket fire wraps to identify loss of material. On the basis of its review, the staff finds the aging effects of loss of material of cerafiber and cera blanket material exposed to a protected from weather environment are effectively managed using the Fire Protection Program. On this basis, the staff finds that management of loss of material of cerafiber and cera blanket fire wraps in bulk commodities is acceptable.In LRA Table 3.5.2-6, the applicant proposed to manage cracking and change in materialproperties for component types seals and gaskets (doors, manways and hatches) of Class I structures other than Group 6 [Note: The actual components are the reactor building railroad inner and outer lock doors elastomer seals] exposed to a protected from weather environment using "Periodic Surveillance and Preventive Maintenance."The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Programand its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 that includes periodic inspections and tests that manage aging effects not managed by other AMPs. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. The staff finds that cracking and change in material properties of seals and gaskets (actual components are the reactor building railroad inner and outer lock doors elastomer seals) exposed to a protected from weather environment is properly managed by the Periodic Surveillance and Preventive Maintenance Program, which in accordance with program element Detection of Aging Effects will perform leakage tests on the reactor building railroad inner and outer doors to verify the absence of significant cracking and change in material properties for the rubber seals. Inspection and testing intervals are dependent on component material and environment and take into consideration industry and plant-specific operating experience and manufacturers' recommendations. Each inspection or test occurs at least once every ten years. On this basis, the staff finds that management of cracking and change in material properties ofseals and gaskets (doors, manways and hatches) of Class I structures other than Group 6 in bulk commodities is adequately managed using the Periodic Surveillance and Preventive Maintenance Program.
3-466On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.5.2.3.7  Aging Effect/Mechanism in LRA Table 3.5.1 That are Not Applicable for VYNPS The staff reviewed LRA Table 3.5.1, which provides a summary of aging managementevaluations for the structures and component supports evaluated in the GALL Report.In the LRA Table 3.5.1, Item 3.5.1-19, the applicant stated that cracking of steel elements:stainless steel suppression chamber shell (inner surface) due to SCC is not applicable at VYNPS. The VYNPS suppression chamber is carbon steel.On the basis that there is no stainless steel suppression chamber shell in the structures andcomponent supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS.In LRA Table 3.5.1, Item 3.5.1-20, the applicant stated that loss of material of steel elements:suppression chamber liner (interior surface) due to general, pitting, and crevice corrosion is not applicable at VYNPS. The applicant further stated that the GALL Report referencing this item are associated with concrete containment. The VYNPS containment is a Mark I steel containment.The staff finds that LRA Table 3.5.1, Item 3.5.1-20 is applicable only to concrete containments.On the basis that there is no suppression chamber liner in the structures and component supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS.In LRA Table 3.5.1, Item 3.5.1-22, the applicant stated that the loss of material of prestressedcontainment: tendons and anchorage components due to corrosion is not applicable at VYNPS.
The applicant further stated that the VYNPS containment is a Mark I steel containment without prestressed tendons.The staff finds that LRA Table 3.5.1, Item 3.5.1-22 is applicable only to concrete containments.On the basis that there are no tendons and anchorage components in the structures and component supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS.In LRA Table 3.5.1, Item 3.5.1-48, the applicant stated that the loss of material and loss of formof Group 6: earthen water control structures-dams, embankments, reservoirs, channels, canals, and ponds due to erosion, settlement, sedimentation, frost action, waves, currents, surface runoff, and seepage is not applicable at VYNPS. The applicant further stated that VYNPS does not have any earthen water control structures.
3-467On the basis that there are no earthen water control structures-dams, embankments, reservoirs,channels, canals, and ponds in the structures and component supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS.In LRA Table 3.5.1, Item 3.5.1-51, the applicant stated that cracking and loss of material ofGroup B1.1: high strength low-alloy bolts due to stress corrosion and general corrosion is not applicable at VYNPS. SCC of high strength anchor bolts is not an AERM at VYNPS for two reasons: (1) high strength bolting at VYNPS is not exposed to a corrosive environment or high tensile stresses and (2) high strength structural bolts are installed with friction-type contact surfaces via the turn-of-the-nut method; therefore, for bolts greater than 1" in diameter, a significant preload (in the order of 70percent of ultimate strength) is not practical to develop. The Inservice Inspection (IWF) Program manages loss of material for high strength low-alloy bolts.The staff finds that cracking of high strength low-alloy bolts due to stress corrosion can occur forGroup B1.1 components. In its letter, dated January 4, 2006, the applicant clarified its Bolting Integrity Program to address all bolts. The staff finds managing aging of bolts with the Bolting Integrity Program, in addition to the Inservice Inspection Program, acceptable because it is consistent with the GALL Report. In LRA Table 3.5.1, Item 3.5.1-52, the applicant addressed loss of mechanical function ofGroups B2, and B4: sliding support bearing and sliding support surfaces due to corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic thermal loads. The applicant stated that loss of mechanical function due to the listed mechanisms is not an aging effect. Proper design prevents distortion, overload, and fatigue due to vibratory and cyclic thermal loads. During the audit and review, the staff asked the applicant to:
Explain how loss of mechanical function due to corrosion is not an aging effect which needs tobe managed for the period of extended operation.
* If proper design prevents distortion, overload, and fatigue due to vibratory and cyclicthermal loads, explain if there has never been a component failure at VYNPS due to any of these conditions.
* Explain if there has never been a component failure in the nuclear industry due to any ofthese conditions.
* Explain where sliding support bearing and sliding support surfaces are used incomponent groups B2 and B4 at VYNPS and provide the environment they are exposed to.During interviews with the applicant's technical personnel, the applicant stated that loss ofmaterial due to corrosion is an aging effect that can cause a loss of intended function. Loss of mechanical function would be considered a loss of intended function. Loss of mechanical function is not an aging effect, but is the result of aging effects. There have been component failures in the industry due to distortion, overload, and excessive vibration. Such failures typically result from inadequate design or events rather than the effects of aging. Failures due to cyclic thermal loads are very rare for structural supports due to their relatively low temperatures.
3-468The applicant also stated that the sliding surface material used at VYNPS is lubrite, which is acorrosion resistant material. Components are inspected in accordance with ISI-IWF for torus saddle supports and Structures Monitoring Program for the lubrite components of radial beam seats. Plant operating experience has not identified failure of lubrite components used in structural applications. No current industry experience has identified failure associated with lubrite sliding surfaces. Components associated with B2 grouping are limited to the torus radial beam seats and support saddles. There are no sliding support surfaces associated with the B4 component grouping for sliding surfaces at VYNPS.In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRATable 3.5.1, Item 3.5.1-52 discussion column is revised to read as follows:Loss of mechanical function due to the listed mechanisms is not an aging effect.Such failures typically result from inadequate design or operating events rather than from the effects of aging. Failures due to cyclic thermal loads are rare for structural supports due to their relatively low temperatures.The staff finds that loss of mechanical function due to distortion, dirt, overload, fatigue due tovibratory, and cyclic thermal loads are not aging effects requiring management. Such failures do typically result from inadequate design or events rather than the effects of aging.On the basis that the mechanisms provided in LRA Table 3.5.1, Item 3.5.1-52, other thancorrosion, are not aging mechanisms which cause aging effects for Group B2 and B4 components in the structures and component supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS.In LRA Table 3.5.1, Item 3.5.1-54, the applicant addressed loss of mechanical function ofGroups B1.1, B1.2, and B1.3: constant and variable load spring hangers; guides and stops due to corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic thermal loads. The applicant stated that loss of mechanical function due to the listed mechanisms is not an aging effect. Proper design prevents distortion, overload, and fatigue due to vibratory and cyclic thermal loads. During the audit and review, the staff asked the applicant to:
* Explain how loss of mechanical function due to corrosion is not an aging effect whichneeds to be managed for the period of extended operation.
* If proper design prevents distortion, overload, and fatigue due to vibratory and cyclicthermal loads, explain if there has never been a component failure at VYNPS due to any of these conditions.
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* Explain if there has never been a component failure in the nuclear industry due to any ofthese conditions.
* Explain what VYNPS inspects for during VT-3 visual examinations of groups B1.1, B1.2and B1.3 components in accordance with its Inservice Inspection Program during its current license and also anticipated VT-3 visual examinations during its possible extended license period.During interviews with the applicant's technical personnel, the applicant stated that thediscussion for LRA Table 3.5.1, Item 3.5.1-54 was not saying that failures have not occurred, but that loss of mechanical function is not an aging effect. For license renewal, Entergy identifies a number of aging effects that can cause loss of intended function. Loss of intended function includes loss of mechanical function. The loss of function is not considered an aging effect.
Aging effects that could cause loss of mechanical function for components in LRA Table 3.5.1, Item 3.5.1-54 are addressed elsewhere in the AMRs. For example, loss of material due to any mechanism is addressed in LRA Table 3.5.2-6 under listings for component and piping supports ASME Code Class 1, 2, 3 and MC (page 3.5-70), and component and piping supports (page 3.5-71). Component failures at VYNPS and in the nuclear industry have certainly occurred due to overload (typically caused by an event such as waterhammer) or vibratory and cyclic thermal loads. Because of the low operating temperatures, failures due to cyclic thermal loads are extremely rare for structural commodities. Failures due to distortion or vibratory loads have also occurred due to inadequate design, but rarely if ever, due to the normal effects of aging.In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRATable 3.5.1, Item 3.5.1-54 discussion is revised to read as follows:Loss of mechanical function due to distortion, dirt, overload, fatigue due tovibratory, and cyclic thermal loads are not aging effects requiring management.
Such failures typically result from inadequate design or events rather than the effects of aging. Loss of material due to corrosion, which could cause loss of mechanical function, is addressed under LRA Table 3.5.1, Item 3.5.1-53 for Groups B1.1, B1.2, and B1.3 support members.The staff finds that loss of mechanical function due to distortion, dirt, overload, fatigue due tovibratory, and cyclic thermal loads are not aging effects requiring management. Such failures do typically result from inadequate design or events rather than the effects of aging.On the basis that the mechanisms provided in LRA Table 3.5.1, Item 3.5.1-54, other thancorrosion, are not aging mechanisms which cause aging effects for group B1.1, B1.2, and B1.3 components in the structures and component supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS.In LRA Table 3.5.1, Item 3.5.1-57, the applicant addressed the reduction or loss of isolationfunction of Groups B1.1, B1.2, and B1.3: vibration isolation elements due to radiation hardening, temperature, humidity, and sustained vibratory loading. The applicant stated that no supports with vibration isolation elements have been identified in the scope of license renewal for VYNPS.
3-470The staff finds that VYNPS does not have Group B1.1, B1.2, and B1.3 vibration isolationelements in the scope of license renewal.On the basis that there are no Group B1.1, B1.2, and B1.3 vibration isolation elements in thestructures and component supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS.3.5.2.3.8  Structures and Component Supports AMR Line Items That Have No Aging Effects(LRA Tables 3.5.2-1 through 3.5.2-6)In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no agingeffects were identified as a result of its aging review process. Specifically, instances in which the applicant stated that no aging effects were identified occurred when components fabricated from concrete material are exposed to a protected from weather, weather or fluid environment. In the LRA the applicant states that inaccessible and accessible concrete areas are designed in accordance with ACI 318-63, which results in low permeability and resistance to aggressive chemical solutions by requiring the following:
* high cement content
* low water-to-cement ratio
* proper curing
* adequate air entrainmentThe applicant also stated that VYNPS concrete also meets guidelines of later guideACI 201.2R-77, since both ACI documents use the same ASTM standards for selection, application and testing of concrete. The below-grade environment is not aggressive (pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1,500 ppm). Concrete was provided with air content between 3percent and 5percent and in general a water/cement ratio between 0.44 and 0.60. Therefore, increase in porosity and permeability due to leaching of calcium hydroxide, cracking, loss of material (spalling, scaling) due to aggressive chemical attack, and cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel are not applicable for concrete in accessible and inaccessible areas.Aggregates used at VYNPS were in accordance with specifications and materials conforming to ACI and ASTM standards. VYNPS concrete structures are constructed of a dense, durable mixture of sound coarse aggregate, fine aggregate, cement, water, and admixture. Therefore, loss of material (spalling, scaling) and cracking due to freeze thaw; and cracking due to expansion and reaction with aggregates are not aging effects requiring management for VYNPS structures. ASME Code, Section III, Division 2, Subsection CC, indicates that aging due toelevated temperature exposure is not significant as long as concrete general area temperatures do not exceed 150F and local area temperatures do not exceed 200F. During normaloperation, areas within the VYNPS primary containment and other structures are within these temperature limits. Therefore, reduction of strength and modulus of concrete structures due to elevated temperature is not an AERM for VYNPS concrete. The staff finds that the quality of the reinforced concrete used at VYNPS meets the codes andstandards referenced in the GALL Report such that concrete is not susceptible to the aging effects listed above. The below-grade environment was finds not to be aggressive at VYNPS with continuing groundwater monitoring to occur during the period of extended license.
3-471Therefore, no aging effects are considered to be applicable to components fabricated fromconcrete material protected from weather, exposed to weather or exposed to fluid environments.
Since the absence of this concrete aging effects needs to be confirmed, concrete components and structures are included within the Structures Monitoring Program.On the basis of its review of current industry research and operating experience, the staff findsthat protected from weather, weather or fluid on concrete will not result in aging that will be of concern during the period of extended operation. The staff finds that the applicant's AMR evaluations that concrete protected from weather, exposed to weather or fluid environments will have no identified aging effects that actually occur, acceptable. Therefore, the staff finds that there are no applicable aging effects requiring management for concrete components exposed to protected from weather, exposed to weather or exposed to fluid environments.During the audit and review, the staff noted that in LRA Table 3.5.2-5 (page 3.5-67), forcomponent Vernon Dam external walls, floor slabs and interior walls, material concrete in a protected from weather environment; the aging effect shown is none with the AMP shown as Vernon Dam FERC Inspection. VYNPS discusses throughout its LRA Section 3.5 further evaluations that VYNPS concrete does not have aging effects because the quality of the concrete used during construction was to the standards of ACI 18-63 and ACI 201.2R-77.
Vernon Dam is a very old structure and was not built by the owners of VYNPS. The staff asked the applicant to provide documentation and justification that the quality of the concrete used at Vernon Dam is also to the standards of ACI 318-63 and ACI 2012.R-77, such that the AMR statement "None" for aging effects of the Dam concrete is justified.During interviews with the applicant's technical personnel, the applicant's staff stated sincequality of concrete used at Vernon Dam has not been confirmed, it would have been more appropriate to show the associated aging effects for the line items in question. However, the same aging management activity, the FERC inspection, is still appropriate to manage aging effects associated with the Vernon Dam concrete components.The staff found that the acceptance of the Vernon Dam FERC Inspection Program along withassociated LRA questions are issues that will require further evaluation. The staff issued RAI 3.6.2.2-N-08 to address this concern, which is evaluated in SER Section 3.0.3.3.6.In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified line items where no aging effectswere identified as a result of its aging review process.In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no agingeffects were identified as a result of its aging review process. Specifically, instances in which the applicant states that no aging effects were identified occurred when components fabricated from lubrite plate material were in a protected from weather environment. The applicant also stated that Lubrite plates are used in the drywell beam seats and the torus support saddles at VYNPS.
Lubrite materials for nuclear applications are designed to resist deformation, have a low coefficient of friction, resist softening at elevated temperatures, resist corrosion, withstand highintensities of radiation, and not score or mar; therefore, they are not susceptible to aging effects requiring management. Due to the wear-resistant material used, the low frequency (number of times) of movement, and the slow movement between sliding surfaces, lock-up and loss of mechanical function of lubrite plates from wear, corrosion, distortion, dirt, overload, fatigue due 3-472to vibratory and cyclic thermal loads are not considered to be aging effects requiringmanagement at VYNPS. Nonetheless, Lubrite plates are included within the Structures Monitoring Program and Inservice Inspection (IWF) Program. Industry operating experience and VYNPS ISI inspection reports for slide bearing plates have identified no recordable degradation due to any aging effects. Therefore, no aging effects are considered to be applicable to components fabricated from lubrite plate material exposed to a protected from weather environment.On the basis of its review of current industry research and operating experience, the staff findsthat a protected from weather environment on lubrite plate will not result in aging that will be of concern during the period of extended operation. The staff finds that the applicant's AMR evaluations that lubrite plate in a protected from weather environment will have no identified aging effects that actually occur, acceptable. Therefore, the staff concludes that there are no applicable aging effects requiring management for lubrite plate components exposed to a protected from weather environment.In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no agingeffects were identified as a result of its aging review process. Specifically, instances in which the applicant states that no aging effects were identified occurred when components fabricated from aluminum material were in a exposed to weather environment.In the LRA the applicant states that the ambient environment at VYNPS is not chemicallypolluted by vapors of SO 2 or other similar substances and the external environment does notcontain saltwater or high chlorides. In this non-aggressive environment, the occasional wetting and drying from normal outdoor weather does not result in any significant loss of material for aluminum components. Therefore, loss of material due to pitting and crevice corrosion is not an AERM for aluminum components exposed to a weather environment. Industry operating experience and previously approved staff positions documented in the Farley SER (NUREG-1825, page 3-314) support the conclusion that there are no aging effects for aluminum in a weather environment. Therefore, no aging effects are considered to be applicable to components fabricated from aluminum material exposed to a weather environment.On the basis of its review of current industry operating experience and approved staff positions,the staff finds that a weather environment on aluminum at VYNPS will not result in aging that will be of concern during the period of extended operation. The staff finds that the applicant's AMR evaluations that aluminum in a weather environment will have no identified aging effects that actually occur, acceptable. Therefore, the staff finds that there are no applicable aging effects requiring management for aluminum components exposed to a weather environment.In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no agingeffects were identified as a result of its aging review process. Specifically, instances in which the applicant states that no aging effects were identified occurred when components fabricated from stainless steel material were in a exposed to weather environment.In the LRA the applicant stated that the ambient environment at VYNPS is not chemicallypolluted by vapors of SO 2 or other similar substances and the external environment does notcontain saltwater or high chlorides. In this non-aggressive environment, the occasional wetting and drying from normal outdoor weather does not result in any significant loss of material for 3-473stainless steel components. Therefore, loss of material due to pitting and crevice corrosion is notan AERM for stainless steel components exposed to a weather environment. Industry operating experience and previously approved staff positions documented in the Farley SER (NUREG-1825, page 3-314) support the conclusion that there are no aging effects for stainless steel in a weather environment. Therefore, no aging effects are considered to be applicable to components fabricated from stainless steel material exposed to a weather environment.On the basis of its review of current industry operating experience and approved staff positions,the staff finds that a weather environment on stainless steel at VYNPS will not result in aging that will be of concern during the period of extended operation. The staff finds that the applicant's AMR evaluations that stainless steel in a weather environment will have no identified aging effects that actually occur, acceptable. Therefore, the staff finds that there are no applicable aging effects requiring management for stainless steel components exposed to a weather environment.In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no agingeffects were identified as a result of its aging review process. Specifically, instances in which the applicant stated that no aging effects were identified occurred when components fabricated from carbon steel material were exposed to weather environment.During the audit and review the staff noted that in LRA Table 3.5.2-4 (page 3.5-61), forcomponent steel piles, material carbon steel exposed to weather environment; the aging effect is none. Note 504 discusses steel piles driven into soils (a soil environment, not a weather environment) with no significant effects due to corrosion. The applicant was asked to explain how the soil environment relates to the weather environment to justify no aging effect.During interviews with the applicant's technical personnel, the applicant's staff stated that asidentified in LRA Table 3.5.2-4 (page 3.5-61), for steel piles, material carbon steel exposed to weather environment; the aging effect is none. Although a soil environment is not identified, the listed environment, exposed to weather, is intended to include both an above grade environment and a below grade environment as described in LRA Table 3.0-2. The below grade environment applies to the steel piles. As such the statement made in Note 504 is applicable.In the LRA, the applicant states that carbon steel piles driven in undisturbed soils show nosignificant effects due to corrosion, regardless of the soil type or soil properties. Likewise, piles driven in disturbed soil above the water table zone do not reflect any significant corrosion.
Therefore, aging management is not required of carbon steel exposed to a weather environment (non-aggressive soil environment). Industry operating experience supports the conclusion that there are no aging effects for carbon steel in a weather environment (non-aggressive soil environment). Therefore, no aging effects are considered to be applicable to components fabricated from carbon steel material exposed to a weather environment (non-aggressive soil environment).On the basis of current industry research and operating experience, the staff finds that aweather environment (non-aggressive soil environment) on carbon steel at VYNPS will not result in aging that will be of concern during the period of extended operation. The staff finds that the 3-474applicant's AMR evaluations that carbon steel in a weather environment (non-aggressive soilenvironment) will have no identified aging effects that actually occur, acceptable. Therefore, the staff finds that there are no applicable aging effects requiring management for carbon steel components exposed to a weather environment (non-aggressive soil environment).In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no agingeffects were identified as a result of its aging review process. Specifically, instances in which the applicant stated that no aging effects were identified occurred when components fabricated from pyrocrete material were in a protected from weather environment.During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-78), forcomponent fire proofing, material Pyrocrete in a protected from weather environment; the aging effect is none. The applicant was asked to provide a technical basis why Pyrocrete does not have any aging effects in the environment listed.During interviews with the applicant's technical personnel, the applicant's staff stated thatPyrocrete (used for fire proofing) is cement base composite material. Pyrocrete is not identified in the GALL Report. As such, VYNPS's technical evaluation of pyrocrete in determining applicable aging effects was the same as that for concrete which is based on EPRI 1002950, "Aging Effects for Structures And Structural Components (Structural Tools)," Revision 1, Section 5. Accordingly, no aging effects were determined for pyrocrete protected from weather.
However, as indicated in LRA Table 3.5.2-6 (page 3.5-78), the Fire Protection Program and Structures Monitoring Program will confirm the absence of significant aging effects throughout the period of extended operation.The staff finds pyrocrete to be a cementitious material that like concrete in a protected fromweather environment will not experience aging effects. Industry operating experience supports the conclusion that there are no aging effects for pyrocrete in a protected from weather environment. Therefore, no aging effects are considered to be applicable to components fabricated from pyrocrete material exposed to a protected from weather environment.
Nonetheless, pyrocrete is included within the Fire Protection Program and Structures Monitoring Program to ensure aging effects such as cracking or loss of material are not occurring.On the basis of current industry research and operating experience, the staff finds that aprotected from weather environment on pyrocrete at VYNPS will not result in aging that will be of concern during the period of extended operation. The staff finds that the applicant's AMR evaluations that pyrocrete in a protected from weather environment will have no identified aging effects that actually occur, acceptable. Therefore, the staff concludes that there are no applicable aging effects requiring management for pyrocrete components exposed to a protected from weather environment.In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no agingeffects were identified as a result of its aging review process. Specifically, instances in which the applicant stated that no aging effects were identified occurred when components fabricated from fiberglass, calcium silicate or Stratafab material were in a protected from weather environment.
In the LRA, the applicant stated that loss of insulating characteristics due to insulation degradation is not an AERM for insulation material. Insulation products, which are made from fiberglass fiber, calcium silicate, stainless steel, and similar materials, that are protected from 3-475weather do not experience aging effects that would significantly degrade their ability to insulateas designed. A review of site operating experience identified no aging effects for insulation used at VYNPS. No aging effects are considered to be applicable to components fabricated from fiberglass, calcium silicate or Stratafab material exposed to a protected from weather environment.On the basis of its review of current industry research and operating experience, the staff findsthat a protected from weather environment on fiberglass, calcium silicate or Stratafab will not result in aging that will be of concern during the period of extended operation. Therefore, the staff concludes that there are no applicable aging effects requiring management for fiberglass, calcium silicate or Stratafab components exposed to protected from weather environments.In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no agingeffects were identified as a result of its aging review process. Specifically, instances in which the applicant states that no aging effects were identified occurred when components fabricated from PVC material were exposed to a protected from weather environment.During the audit and review the staff noted that in LRA Table 3.5.2-6 (page 3.5-80), forcomponent water stops, material PVC in a protected from weather environment; the aging effect is none. By definition the component stops water, so it could be exposed to water. In LRA Table 3.5.2-4 (page 3.5-64) for component cooling tower fill, material PVC, environment exposed to fluid environment, the aging effects listed are cracking and change in material properties. The applicant was asked to provide a technical basis why PVC water stops do not have any aging effects which need aging management when they could be exposed to a fluid environment also. The applicant was also asked to provide the specification that called for PVC water stops during construction instead of rubber.During interviews with the applicant's technical personnel, the applicant's staff stated that thePVC water stops identified in LRA Table 3.5.2-6 (page 3.5-80) are used in the cooling tower reinforced concrete basin and are not exposed to the same environment as the cooling tower fill material. Therefore, the aging effects are not the same. The aging effects attributed to PVC water stops are evaluated based upon EPRI 1002950, Section 7.0, "Structural Tools." Exposure to water for these commodities is insignificant, since the concrete encapsulating the PVC waterstop and the protection provided by the surrounding concrete, provides ample protection such that aging management is not required. UFSAR Figure 12.2-33 (G-200357) "Cooling Tower No.2 Basin Plan View" identifies the use of PVC water stops at VYNPS.On the basis that PVC water stops are almost totally encapsulated in concrete to protect themfrom a fluid environment and expose them only to a protected from weather environment, the staff finds that a protected from weather environment on PVC will not result in aging that will be of concern during the period of extended operation. Therefore, the staff concludes that there are no applicable aging effects requiring management for PVC components exposed to a protected from weather environment.
3-476On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.5.3  ConclusionThe staff concludes that the applicant has provided sufficient information to demonstrate that theeffects of aging for the SC supports components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.6  Aging Management of Electrical a nd Instrumentation and Controls SystemThis section of the SER documents the staff's review of the applicant's AMR results for theelectrical and instrumentation and control (I&C) system components and component groups of:
* insulated cables and connections
* transmission conductors
* switchyard bus
* high-voltage insulators3.6.1  Summary of Technical Information in the ApplicationLRA Section 3.6 provides AMR results for the electrical and I&C system components andcomponent groups. LRA Table 3.6.1, "Summary of Aging Management Evaluations for the Electrical and I&C Components," is a summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the electrical and I&C system components and component groups.The applicant's AMRs evaluated and incorporated applicable plant-specific and industryoperating experience in the determination of AERMs. The plant-specific evaluation included condition reports and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.3.6.2  Staff EvaluationThe staff reviewed LRA Section 3.6 to determine whether the applicant provided sufficientinformation to demonstrate that the effects of aging for the electrical and I&C system components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRswere consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the 3-477LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. Thestaff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's audit evaluation are documented in SER Section 3.6.2.1.In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for whichfurther evaluation is recommended. The staff confirmed that the applicant's further evaluations were consistent with the SRP-LR Section 3.6.2.2 acceptance criteria. The staff's audit evaluations are documented in SER Section 3.6.2.2.The staff also conducted a technical review of the remaining AMRs that were not consistent with,or not addressed in, the GALL Report. The technical review evaluated whether all plausible aging effects have been identified and whether the aging effects listed were appropriate for the material-environment combinations specified. The staff's evaluations are documented in SER Section 3.6.2.3.For SSCs which the applicant claimed were not applicable or required no aging management,the staff reviewed the AMR line items and the plant's operating experience to verify the applicant's claims.Table 3.6-1 summarizes the staff's evaluation of components, aging effects/mechanisms, andAMPs listed in LRA Section 3.6 and addressed in the GALL Report.Table 3.6-1  Staff Evaluation for Electrical and I&C Components in the GALL ReportComponent Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation Electrical equipment subject to 10 CFR 50.49 Environmental Qualification Requirements
 
(3.6.1-1)Degradation due tovarious aging
 
mechanismsEnvironmentalQualification of Electric ComponentsTLAAEnvironmentalQualification of Electric Components
 
Program (B.1.10)Consistent withGALL Report, which
 
recommends further evaluation (See
 
SER Section 3.6.2.2.1)
Electrical cables, connections and
 
fuse holders (insulation) not
 
subject to 10 CFR 50.49 Environmental Qualification Requirements
 
(3.6.1-2)Reduced insulation resistance and
 
electrical failure due to various physical, thermal, radiolytic, photolytic, and
 
chemical mechanismsElectrical Cablesand Connections
 
Not Subject to 10 CFR 50.49 Environmental Qualification RequirementsNon-EnvironmentalQualification Insulated Cables and Connections
 
Program (B.1.19)Consistent withGALL Report. (See
 
SER Section 3.6.2.1)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-478Conductor insulation for
 
electrical cables and
 
connections used in
 
instrumentation
 
circuits not subject to 10 CFR 50.49 Environmental Qualification
 
requirements that are sensitive to
 
reduction in
 
conductor insulation resistance (IR)
 
(3.6.1-3)Reduced insulation resistance and
 
electrical failure due to various physical, thermal, radiolytic, photolytic, and
 
chemical mechanismsElectrical CablesAnd Connections Used In Instrumentation Circuits Not Subject To 10 CFR 50.49 Environmental Qualification RequirementsNon-EnvironmentalQualification
 
Instrumentation Circuits Test Review
 
Program (B.1.18)Consistent withGALL Report. (See
 
SER Section 3.6.2.1)Conductor insulation for
 
inaccessible medium voltage
 
(2 kV to 35 kV)
 
cables (e.g., installed in
 
conduit or direct
 
buried) not subject to 10 CFR 50.49 Environmental Qualification Requirements
 
(3.6.1-4)Localized damageand breakdown of
 
insulation leading to
 
electrical failure due
 
to moisture intrusion, water
 
trees InaccessibleMedium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification RequirementsNon-EnvironmentalQualification
 
Inaccessible Medium-Voltage Cable Program (B.1.17)Consistent withGALL Report. (See
 
SER Section 3.6.2.1)Connector contacts for electrical connectors exposed to borated water
 
leakage (3.6.1-5)Corrosion of connector contact
 
surfaces due to
 
intrusion of borated waterBoric AcidCorrosionNoneNot applicable toBWRsFuse Holders(Not Part of a Larger Assembly): Fuse
 
holders - metallic
 
clamp (3.6.1-6)Fatigue due to ohmic heating, thermal cycling, electrical transients, frequent manipulation, vibration, chemical
 
contamination, corrosion, and oxidationFuse HoldersNoneAMR results that arenot consistent with the GALL Report or
 
not addressed in the GALL Report. (See
 
SER Section 3.6.2.3)Metal-EnclosedBus -
Bus/connections
 
(3.6.1-7)Loosening of bolted connections due to thermal cycling and
 
ohmic heatingMetal-Enclosed BusMetal-Enclosed Bus ProgramAMR results that arenot consistent with the GALL Report or
 
not addressed in the GALL Report. (See
 
SER Section 3.6.2.3)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-479Metal-EnclosedBus -
Insulation/insulators
 
(3.6.1-8)Embrittlement, cracking, melting, discoloration, swelling, or loss
 
dielectric strength
 
leading to reduced
 
insulation
 
resistance; electrical
 
failure due to
 
thermal/
thermoxidative
 
degradation of
 
organics/
thermoplastics, radiation-induced oxidation;
 
moisture/debris
 
intrusion, and ohmic
 
heatingMetal-Enclosed BusMetal-Enclosed Bus ProgramAMR results that arenot consistent with the GALL Report or
 
not addressed in the GALL Report. (See
 
SER Section 3.6.2.3)Metal-EnclosedBus - Enclosure
 
assemblies
 
(3.6.1-9)Loss of material due to general corrosion StructuresMonitoring ProgramMetal-Enclosed Bus ProgramAMR results that arenot consistent with the GALL Report or
 
not addressed in the GALL Report. (See
 
SER Section 3.6.2.3)Metal-EnclosedBus - Enclosure
 
assemblies
 
(3.6.1-10)Hardening and loss of strength due to
 
elastomers
 
degradation StructuresMonitoring ProgramMetal-Enclosed Bus ProgramAMR results that arenot consistent with the GALL Report or
 
not addressed in the GALL Report. (See
 
SER Section 3.6.2.3)High-voltage insulators
 
(3.6.1-11)Degradation of insulation quality
 
due to presence of any salt deposits
 
and surface
 
contamination; Loss
 
of material caused by mechanical wear due to wind blowing
 
on transmission
 
conductors A plant-specificAMP is to be evaluatedNoneConsistent with theGALL Report, which
 
recommends further evaluation.
(See SER Section 3.6.2.2.2)
Component Group(GALL Report Item No.)Aging Effect/
MechanismAMP in GALL ReportAMP in LRAStaff Evaluation3-480Transmission conductors and
 
connections; switchyard bus and
 
connections
 
(3.6.1-12)
Loss of material dueto wind induced
 
abrasion and
 
fatigue; loss of
 
conductor strength
 
due to corrosion;
 
increased resistance of
 
connection due to oxidation or loss of
 
preload A plant-specificAMP is to be evaluatedNoneConsistent with theGALL Report, which
 
recommends further evaluation.
(See SER Section 3.6.2.2.3)Cable Connections -Metallic parts
 
(3.6.1-13)
Loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical
 
contamination, corrosion, and oxidationElectrical CableConnections Not Subject To 10 CFR 50.49 Environmental Qualification RequirementsNoneAMR results that arenot consistent with the GALL Report or
 
not addressed in the GALL Report. (See
 
SER Section 3.6.2.3)Fuse Holders(Not Part of a Larger Assembly)
Insulation material
 
(3.6.1-14)NoneNoneNoneAMR results notconsistent with GALL Report or not addressed in GALL
 
Report (See SER
 
Section 3.6.2.3)The staff's review of the electrical and I&C system component groups followed any one ofseveral approaches. One approach, documented in SER Section 3.6.2.1, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.6.2.2, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.6.2.3, reviewed AMR results for components that the applicant indicated are not consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the electrical and I&C system components is documented in SER Section 3.0.3.3.6.2.1  AMR Results Consistent with the GALL ReportSummary of Technical Information in the Application. LRA Section 3.6.2.1 identifies thematerials, environments, AERMs, and the following programs that manage aging effects for the electrical and I&C system components:
* Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program
* Non-Environmental Qualification Instrumentation Circuits Test Review Program
* Non-Environmental Qualification Insulated Cables and Connections Program 3-481LRA Table 3.6.2-1 summarizes AMRs for the electrical and I&C system components andindicates AMRs claimed to be consistent with the GALL Report.Staff Evaluation. For component groups evaluated in the GALL Report for which the applicantclaimed consistency with the report and for which it does not recommend further evaluation, the staff's audit and review determined whether the plant-specific components of these GALL Report component groups were bounded by the GALL Report evaluation.The applicant noted for each AMR line item how the information in the tables aligns with theinformation in the GALL Report. The staff audited those AMRs with notes A through E indicating how the AMR is consistent with the GALL Report.Note A indicates that the AMR line item is consistent with the GALL Report for component,material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP.
The staff audited these line items to verify consistency with the GALL Report and validity of the AMR for the site-specific conditions.Note B indicates that the AMR line item is consistent with the GALL Report for component,material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify consistency with the GALL Report and verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also finds whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions.Note C indicates that the component for the AMR line item, although different from, is consistentwith the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified in the GALL Report a different component with the same material, environment, aging effect, and AMP as the component under review. The staff audited these line items to verify consistency with the GALL Report. The staff also finds whether the AMR line item of the different component was applicable to the component under review and whether the AMR was valid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different from, is consistentwith the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component was applicable to the component under review and whether the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also finds whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions.Note E indicates that the AMR line item is consistent with the GALL Report for material,environment, and aging effect, but credits a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also finds whether the credited AMP would manage the aging effect consistently with the GALL AMP and whether the AMR was valid for the site-specific conditions.
3-482The staff audited and reviewed the information in the LRA. The staff did not repeat its review ofthe matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluation follows.The staff evaluated the applicant's claim of consistency with the GALL Report. The staff alsoreviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed consistent with its AMRs. Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.6.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is RecommendedSummary of Information in the Application. In LRA Section 3.6.2.2, the applicant furtherevaluates aging management, as recommended by the GALL Report, for the electrical and I&C system components and provides information concerning how it will manage the following aging effects:
* electrical equipment subject to environmental qualification
* degradation of insulator quality due to salt deposits or surface contamination, loss ofmaterial due to mechanical wear
* loss of material due to wind induced abrasion and fatigue, loss of conductor strength dueto corrosion, and increased resistance of connection due to oxidation or loss of pre-load
* quality assurance for aging management of nonsafety-related componentsStaff Evaluation. For component groups evaluated in the GALL Report, for which the applicantclaimed consistency with the report and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations against the criteria contained in SRP-LR Section 3.6.2.2. The staff's review of the applicant's further evaluation follows.3.6.2.2.1  Electrical Equipment Subject to Environmental Qualification In LRA Section 3.6.2.2.1, the applicant stated that environmental qualification is a TLAA, asdefined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.4 documents the staff's review of the applicant's evaluation of this TLAA.
3-4833.6.2.2.2  Degradation of Insulator Quality Due to Salt Deposits or Surface Contamination, Lossof Material Due to Mechanical WearThe staff reviewed LRA Section 3.6.2.2.2 against the criteria in SRP-LR Section 3.6.2.2.2.
In LRA Section 3.6.2.2.2, the applicant stated that for the degradation of insulator quality due topresence of any salt deposits and surface contamination, and loss of material due to mechanical wear, this aging effect is not applicable to VYNPS.SRP-LR Section 3.6.2.2.2 states that degradation of insulator quality due to salt deposits orsurface contamination may occur in high-voltage insulators. The GALL Report recommends further evaluation of plant-specific AMPs for plants at locations of potential salt deposits or surface contamination (e.g., in the vicinity of salt water bodies or industrial pollution). Loss of material due to mechanical wear caused by wind on transmission conductors may occur in high-voltage insulators. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed.The applicant stated, in the LRA, that the insulators evaluated for VYNPS license renewal arethose used to support uninsulated, high-voltage electrical components such as transmissionconductors and switchyard buses.The applicant further stated, in the LRA, that various airborne materials such as dust, salt andindustrial effluents can contaminate insulator surfaces. The buildup of surface contamination in most areas is washed away by rain. The glazed insulator surface aids this contamination removal. However, a large buildup of contamination enables the conductor voltage to track along the surface more easily and can lead to insulator flashover. The applicant stated, that VYNPS is not located near the seacoast where salt spray is considered. At VYNPS, contamination build-up on insulators is not a concern. Therefore, surface contamination is not an applicable aging mechanism for high-voltage insulators at VYNPS.The staff noted that surface contamination can be a problem in areas where there are greaterconcentration of airborne particles such as near facilities that discharge soot. The staff asked the applicant to clarify why surface contamination is not a concern at VYNPS. In its response, the applicant stated that VYNPS is not located near facilities that discharge soot. At VYNPS, as in most areas of the New England transmission system, contamination buildup on insulators is not a problem. Therefore, the applicant concluded that surface contamination is not an applicable aging mechanism for insulators at VYNPS. The staff finds the applicant's response acceptable because surface contamination can be a problem in areas where there are greater concentration of airborne particles such as near facilities that discharge soot. Since VYNPS is not located near facilities that discharge soot, surface contamination is not an applicable aging effect for high-voltage insulators.In the LRA, the applicant also stated, that mechanical wear is an aging effect for strain andsuspension insulators in that they are subject to movement. Although this mechanism is possible, industry experience has shown that transmission conductors do not normally swing and that when they do, due to a substantial wind, they do not continue to swing for very long once the wind has subsided. Wear has not been apparent during routine inspections. The staff finds the applicant's assessment acceptable.
3-484The staff concludes that there are no aging effects requiring management for VYNPShigh-voltage insulators. The staff finds that the degradation of insulator quality due to presence of any salt deposits and surface contamination, and loss of material due to mechanical wear is not an applicable AERM.Based on the programs identified above, the staff concludes that the applicant's programs meetSRP-LR Section 3.6.2.2.2 criteria. For those line items that apply to LRA Section 3.6.2.2.2, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.6.2.2.3  Loss of Material Due to Wind-Induced Abrasion and Fatigue, Loss of ConductorStrength Due to Corrosion, and Increased Resistance of Connection Due to Oxidation or Loss ofPre-LoadThe staff reviewed LRA Section 3.6.2.2.3 against the criteria in SRP-LR Section 3.6.2.2.3.
In LRA Section 3.6.2.2.3, the applicant stated that for the loss of material due to wind inducedabrasion and fatigue, loss of conductor strength due to corrosion, and increased resistance of connection due to oxidation or loss of pre-load, this aging effect is not applicable to VYNPS.SRP-LR Section 3.6.2.2.3 states that loss of material due to wind-induced abrasion and fatigue,loss of conductor strength due to corrosion, and increased resistance of connection due to oxidation or loss of pre-load may occur in transmission conductors and connections and in switchyard bus and connections. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed.The applicant stated, in the LRA, that transmission conductors are uninsulated, strandedelectrical cables used outside buildings in high-voltage applications. The transmission conductorcommodity group includes the associated fastening hardware, but excludes the high-voltageinsulators. Major active equipment assemblies include their associated transmission conductor terminations.In LRA Table 3.6.2-1, under the transmission conductors, the applicant stated that no agingeffects requiring management and no AMP is required. During the audit and review, the staff noted that the most prevalent mechanism contributing to loss of conductor strength of aluminum core steel reinforce (ACSR) transmission conductor is corrosion which includes corrosion of steel core and aluminum strand pitting. Degradation begins as a loss of zinc from the galvanized steel core wires. Corrosion rates depend largely on air quality, which includes suspended particle chemistry, SO 2 concentration in air, precipitation, fog chemistry and meteorologicalconditions. The staff asked the applicant to clarify why loss of conductor strength is not an AERM for transmission conductors at VYNPS. In its response, the applicant stated that the prevalent mechanism contributing to loss of an ACSR transmission conductor is corrosion, which includes corrosion of the steel core and aluminum strand pitting. Corrosion in the ACSRconductor is a very slow acting mechanism, and the corrosion rates depend on air quality, which includes suspended particles chemistry, SO 2 concentration in air, precipitation, fog chemistryand meteorological conditions. Air quality in rural areas generally contains low concentration of 3-485suspended particles and SO 2, which keeps the corrosion rate to a minimum. Tests performed byOntario Hydro showed a 30 percent loss of composite conductor strength of an 80-year old ACSR conductor due to corrosion. The National Electric Safety Code (NESC) requires that tension on installed conductors be a maximum of 60 percent of the ultimate conductor strength.
The acceptance criteria for VYNPS is less than 40 percent loss of composite conductor strength per NESC. Aluminum conductor alloy reinforced (ACAR) conductors are used at VYNPS as well as ACSR conductors. ACAR conductors are more resistant to loss of conductor strength since the core of the conductor is an alloy steel and corrosion resistant metals. Conclusion for ACSR conductors conservatively bound ACAR conductors. Therefore, corrosion of transmission conductor is not an AERM and an AMP is not required. The staff finds the applicant's response acceptable because corrosion of the ACSR conductor is a very slow acting mechanism and the test data from Ontario Hydro has shown why loss of conductor strength is not an AERM at
 
VYNPS.In addition, the applicant responded that loss of material wear can be an aging effect for strainand suspension insulators that are subject to movement caused by transmission conductor vibration or sway from wind loading. Design and installation standards for transmission conductors consider sway caused by wind loading. Experience has shown that transmission conductors do not normally swing and that when they do, due to a substantial wind, they do not continue to swing for very long once the wind has subsided. Wear has not been identified during routine inspection; therefore, loss of material due wear is not an significant AERM.In the LRA, the applicant stated that transmission conductors are subject to an AMR if they arenecessary for recovery of offsite power following an SBO. At VYNPS, transmission conductors located between switchyard breakers K-1/K-186 and startup transformers T-3-1A/T-3-1B support recovery from an SBO event. Other transmission conductors are not subject to an AMR since they do not perform a license renewal intended function. Switchyard bus is uninsulated, un-enclosed, rigid electrical conductors used in medium and high-voltage applications.
Switchyard bus includes the hardware used to secure the bus to high-voltage insulators.
Switchyard bus establishes electrical connections to disconnect switches, switchyard breakers,and transformers. Switchyard bus located at the disconnect switches at the VHS switchyard are necessary for connecting the AAC power source from the Vernon Dam to essential station switchgear and are subject to an AMR. Also, switchyard bus located at the switchyard breakers K-1/K-186 and at startup transformers T-3-1A/T-3-1B that support recovery from an SBO event are subject to an AMR. Other switchyard bus does not require an AMR since they do not perform a license renewal intended function.The applicant further stated, in the LRA, that connection surface oxidation for aluminumswitchyard bus is not applicable since switchyard bus connections requiring an AMR are welded connections. For ambient environmental conditions at VYNPS, no aging effects have been identified that could cause a loss of intended function for the period of extended operation.
Vibration is not applicable since flexible connectors connect switchyard bus. Therefore, there are no aging effects requiring management for aluminum switchyard bus.The staff noted that transmission conductor connections and switchyard bus connections maybe subject to increased resistance of connection due to oxidation or loss of pre-load. Torque relaxation for bolted connection is a concern for transmission conductor and switchyard bus connections. An electrical connection must be designed to remain tight with good conductivity 3-486through a large temperature range. Meeting this design requirement is difficult if the materialspecified for the bolt and the conductor are different and have different rates of thermal expansion. For example, copper or aluminum bus/conductor materials expand faster than most bolting materials. If thermal stress is added to stresses inherent at assembly, the joint members or fasteners can yield. If plastic deformation occurs during thermal loading (i.e., heat-up) when the connection cools, the joint will be loose. EPRI document TR-104213, "Bolted Joint Maintenance & Application Guide," recommends inspection of bolted joints for evidence of overheating, signs of burning or discoloration, and indication of loose bolts. The staff asked theapplicant to address increased resistance of transmission conductor and switchyard bus connections due to oxidation and loss of pre-load. In its response, the applicant stated that connection surface oxidation for aluminum switchyardbus is not applicable since all switchyard bus connections requiring an AMR are weldedconnections. No aging effects have been identified for welded connections on switchyard bus for SBO. Electrical bolted connections may exist in the path used for SBO between the switchyard breaker and the station transformers. These connections may exist at the high-voltage circuit breakers, circuit breaker disconnect switches, switchyard disconnect switches, transmission conductors and transformer high-voltage and low voltage terminations. VYNPS has evaluated plant operating experience for aging of bolted connections and has no indication of aging mechanism due to loose connections. Except for the connections associated with normally enclosed transformer connections, VYNPS will use its existing thermography program to assure the integrity of bolted connections associated with the path used for SBO between the switchyard breakers in the license renewal scope and the station transformers. Thermography will be performed on switchyard components on a frequency of once every 6 months. Bolted connections associated with transformer are disconnected, inspected and reconnected every operating cycle as part of routine transformer testing and maintenance. VYNPS shall rely on this inspection to assure the integrity of bolted connections associated with the station transformers because thermography can not effectively measure any hot spot temperature within normally enclosed transformer termination enclosures. The staff finds the applicant's response acceptable because for transmission conductor andswitchyard bus connections to transformers, routine transformer testing and maintenance will be used to ensure the integrity of bolted connection and thermography will be used to detect high heat created by increased resistance due to oxidation and loosening of bolted connections associated with other components used for SBO recovery path.The staff finds that the loss of material due to wind induced abrasion and fatigue, loss ofconductor strength due to corrosion are not applicable aging effects requiring management. For potential aging effects of increased resistance of connection due to oxidation or loss of pre-load, the applicant will perform preventive maintenance and thermography to detect the potential aging effects of switchyard bus and transmission conductor bolted connections.Based on the programs identified above, the staff finds that the applicant's programs meetSRP-LR Section 3.6.2.2.3 criteria. For those line items that apply to LRA Section 3.6.2.2.3, the staff finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-4873.6.2.2.4  Quality Assurance for Aging Management of Nonsafety-Related ComponentsSER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.
 
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff finds that the applicant adequately addressed the issues that were further evaluated. The staff finds that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.6.2.3  AMR Results Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Table 3.6.2-1, the staff reviewedadditional details of the AMR results for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report.In LRA Table 3.6.2-1, the applicant indicated, via notes F through J, that the combination ofcomponent type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information about how it will manage the aging effects. Specifically, note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.Staff Evaluation. For component type, material, and environment combinations not evaluated inthe GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff's evaluation is documented in the following sections.3.6.2.3.1  Electrical and I&C Components Summary of Aging Management Evaluation-LRATable 3.6.2-1The staff reviewed LRA Table 3.6.2-1, which summarizes the results of AMR evaluations for theelectrical and I&C components and component groups.In LRA, Table 3.6.2-1, the applicant stated that no aging effects requiring management and noAMP is required for cable connections (metallic parts) in a heat and air outdoor weather environment.During the audit and review, the staff noted that electrical cable connections are subject to theabove aging stressors. GALL AMP XI.E6, "Electrical Cable Connection not Subject to 10 CFR 50.49 Environmental Qualification Requirements," specifies that connections 3-488associated with cables within the scope of license renewal are part of this program, regardless oftheir association with active or passive components. The staff requested that the applicant provide a basis document including an AMP with theprogram elements for cable connections or a technical justification for why an AMP was not necessary. In its response, the applicant stated that an evaluation of thermal cycling, ohmic heating, electrical transient, vibration, chemical contamination, corrosion, and oxidation stressorsfor the metallic parts of electrical cable connections identified no aging effects requiring management. Metallic parts of electrical cable connections potentially exposed to thermal cyclingand ohmic heating are those carrying significant current in power supply circuits. Typically, power cables are in a continuous run from the supply to the load. Therefore, the applicant stated that the connections are part of an active component that is controlled by the Maintenance Rule and is not subject to an AMR. The fast action of circuit protective devices at high currents mitigates stresses associated with electrical faults and transients. In addition, mechanical stressassociated with electrical faults is not a credible aging mechanism because of the low frequencyof occurrence for such faults. Therefore, the applicant stated that electrical transient are not applicable stressors. Metallic parts of electrical cable connections exposed to vibration are those associated with active components that cause vibration. Since active components are controlled by maintenance rule, they are not subject to an AMR. Corrosive chemicals are not stored in most areas of the plant. Routine releases of corrosive chemicals to areas inside plant building do not occur during plant operation. Such a release, and its effects, would be an event, not an effect of aging. The location of electrical connections inside active components protects the metallic parts from contamination. Therefore, the applicant stated that this stressor is not applicable. Oxidation and corrosion usually occur in the presence of moisture or contamination such as industrial pollutants and salt deposits. Enclosures or splice materials protect metal connections from moisture or contamination. Therefore, the applicant stated that oxidation and corrosion are not applicable stressors. Based on the above evaluation, the applicant concluded that there are no aging effects requiring management for metallic components of connections and no AMP is required. The staff reviewed the applicant's response. The staff disagrees with the applicant'sdetermination. Cable connections are passive components and in-scope of license renewal.
Loosening of these bolted connections is an aging effect that need to be managed. Thermal cycling, ohmic heating, electrical transients, vibrations, chemical contamination, corrosion, andoxidation are aging mechanisms. Connections associated with cables in-scope of license renewal are part of this program, regardless of their association with active or passive components. Cable lugs are an integral part of cables. The integrity of lugs can be verified by testing connections. GALL AMP XI.E1 is used to manage connections in adverse locations only and inspects insulation degradation. Most connections are not located in adverse locations.
Institute of Electrical and Electronics Engineers Std. P1205, SAND 96-0344, "Aging Management Guidelines For Electrical Cable and Terminations," indicated loose terminationswere identified by several plants. EPRI-TR-104213, "Bolted Joint Maintenance & Application Guide," indicates that it is difficult to maintain tightness of electrical connections and good conductivity through a large temperature range if the materials for the bolt connections and conductors are different and have different rates of thermal expansion. For example, copper and 3-489aluminum expand faster than most bolting materials. The staff was not aware of any actiontaken to mange the aging effects of cable connections. Several licensee event reports indicated loose connections due to corrosion, vibration, thermal cycling, etc. Also, past applicants have used thermography to detect weak/loose connections and corrected them as soon as possible, and provided an AMP consistent with GALL AMP XI.E6 to manage aging effects of bolted connections. The staff requested in RAI 3.6.2.2-N-01 that the applicant provide basis document including anAMP with its ten program elements for cable connections or technical justification for why an AMP is not necessary. In response to the staff's RAI 3.6.2.2-N-01, in letter dated July 14, 2006, License Renewal Application Amendment 4, the applicant stated that:Electrical cable connections at VYNPS are inspected in accordance with themaintenance rule program as directed by Entergy procedures. The maintenance rule program is in compliance with 10 CFR 50.65. The maintenance rule program is based on industry guidance provided in NUMARC 93-01 and RG  1.160. The maintenance rule program scope includes the following: SSCs, nonsafety-related SSCs that mitigate accidents or transients, nonsafety- related SSCs used in emergency operating procedures, nonsafety-related SSCs whose failure could prevent safety-related SSCs from fulfilling their safety function, and nonsafety- related SSCs whose failure could cause a scram or safety system actuation. Electrical cable connections are subcomponents of SSCs that are in the scope of the maintenance rule. The maintenance rule program includes performance monitoring and trending for SSCs that are in-scope.
Monitoring and trending is performed frequently enough to detect and correct degrading equipment performance, used to evaluate equipment performance following maintenance or modification, based on manufacturer's recommendations, operational or industry experiences with plant equipment or plant-specific information, subject to the corrective action and work order programs, and subject to management review and oversight.
Monitoring and trending includes normal plant maintenance activities. Maintenance includes activities associated with identifying and correcting actual or potential degraded conditions (e.g.,repair, surveillance, diagnostic examinations, and preventive measures) as well as support functions for the conduct of these activities. Thermography is used to detect potential degraded conditions. Thermography can detect "hot spots" in cable connections that are indicative of a high resistance connection. As a part of the maintenance rule program, periodic assessments are performed. A periodic assessment is performed to evaluate the effectiveness of maintenance activities. This assessment is performed at least every operating cycle, not to exceed 24 months. Plant operating experience has shown that the maintenance rule program has been effective at detecting, evaluating and repairing electrical cable connection degradation. Since the maintenance rule program includes scoping, performance monitoring, trending and periodic assessments, this program provides reasonable assurance that electrical cableconnections will remain capable of performing their intended functions through the period of extended operation. No AMP for license renewal is required at VYNPS since the regulatory mandated maintenance rule program effectively maintains electrical cable connections.
3-490The staff reviewed the applicant's response and in a followup to RAI 3.6.2.2-N-01 stated that thecurrent licensing bases for all power plants require compliance with the requirements of the 10 CFR 50.65, the Maintenance Rule. The Statements of Consideration (SOC) for the License Renewal Rule states: The license renewal rule excludes "active, short-lived structures and components" from an AMR because of the existing regulatory process, existing applicant programs and activities, and the Maintenance Rule. The staff's understanding has been that in accordance with the License Renewal Rule, existing programs are not, without some explanation or modification, automatically considered adequate to manage aging effects for license renewal by virtue of being part of the CLB . The Commission formulated the following two principles of license renewal: (1) With the possible exception of the detrimental effects of aging on the functionality of certain plant systems, structures, and components in the period of extended operation and possibly a few other issues related to safety only during extended operation, the regulatory process is adequate to ensure that the licensing bases of all currently operating plants provides and maintains an acceptable level of safety so that operation will not be inimical to public health and safety or common defense and security; and (2) The plant-specific licensing basis must be maintained during the renewal term in the same manner and to the same extent as during the original licensing term. In addition,10 CFR 50.24(a)(3) requires an applicant to demonstrate that the effects of aging, ofcomponents such as cable connections defined in 10 CFR 50.24(a)(1), will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. To demonstrate that the effects of aging will be adequately managed for license renewal, the staff's view is that an applicant must identify the program relied upon to manage certain aging effects for cable connections. The AMP-for cable connections acceptable to the staff should be consistent with GALL AMP XI.E6. GALL AMP XI.E6 accounts for the following stressors: thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation for electrical cableconnections (metallic parts). Therefore, the staff requested, in RAI 3.6.2.2-N-01, that the applicant either provide aplant-specific AMP that addresses the program elements found in SRP-LR, Section A.1, Section A.1.2.3 and SRP-LR Table A.1-1 or an AMP consistent with GALL AMP XI.E6. If the applicant still insisted an AMP is not required, the staff requested that the applicant provide technical justification that addresses how existing programs will address the above aging effects and provide detailed discussion of how its current program meets the program elements as described in the SRP-LR.The staff also requested that the applicant provide supporting documentation to show that theAMP program elements, including appropriate tests, are implemented currently and will be continued for the period of extended operation. Without such information, it was not apparent that the staff would be able to present a basis for concluding that actions have been or will be taken to manage the effects of aging to ensure the intended function of these structures and components during the period of extended operation.
3-491In a letter dated January 4, 2007, License Renewal Application, Amendment 23, the applicantprovided clarification for RAI 3.6.2.2-N-01. Specifically, the applicant, in its letter, stated:Based on a November 30, 2006 NEI meeting with the NRC, the revised oralternate XI.E6 program will be a one-time inspection on representative sample of cable connections subject to an AMR.The License Renewal Project identified connections to include in the AMP byevaluating the VYNPS non-Environmental qualification bolted cable connections.
Switchyard connections are not addressed in this program. Since these connections operate at a much higher voltage (greater than35kV); they are addressed separately as part of the switchyard commodity types.Connections for all voltage levels are considered. Bolted connections are themain concern. The stressors thermal cycling, ohmic heating, and electrical transients are potential stressors only for high-load connections.Thermal cycling, ohmic heating, and electrical transients are not potentialstressors for low-load connections. Low-load connections located in a controlled environment are not included in the program, because vibration, chemical contamination, corrosion and oxidation are not of concern. Low-load in-scope connections to field instrumentation such as pressure transmitters, resistant temperature detectors (RTDs), and flow transmitters are not subject to an AMR, because the in-scope instrumentation located in a harsh environment is typically environmental qualification, and the non-Environmental qualification sensitive instrument circuit (high radiation and neutron monitoring) connections are included in the XI.E2 program.The applicant also revised its LRA by adding LRA Appendices A.2.2.39 and B.1.33 describing itsBolted Cable Connections Program. It also revised Section 3.6.2.1, Aging Effects Requiring Management, Section 3.6.2.1, Aging Management Program, Table 3.6.1, and Table 3.6.2-1. The applicant also included the plant-specific program elements for Bolted Cable Connections Program. The staff's evaluation of the applicant's Bolted Cable Connections Program is documented inSER Section 3.0.3.3.8. In response to NEI's White Paper on GALL AMP XI.E6, which was submitted on September 5, 2006 for staff's review, the staff finds that a few operating experience related to failed connections due to aging have been identified and these operating experience can not support a periodic inspection as currently recommended in GALL AMP XI.E6.On the basis of its review, the staff finds that the applicant's response to RAI 3.6.2.2-N-01 isacceptable. The staff finds that the design of these connections will account for the stress associated with ohmic heating, thermal cycling, and dissimilar connections. The one-time inspection will ensure that either aging of metallic cable connections is not occurring or existingmaintenance program is effective such that a periodic inspection is not required. Therefore, the staff's concern described in RAI 3.6.2.2-N-01 is resolved.
3-492On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMRresults of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.6.2.3.2  Aging Effect/Mechanism in Table 3.6.1 That are Not Applicable for VYNPS The staff reviewed LRA Table 3.6.1, which provides a summary of aging managementevaluations for the electrical and I&Cs evaluated in the GALL Report.The staff noted that electrical and I&C containment penetrations are not addressed in the LRA.The staff asked the applicant if all electrical and I&C containment penetration are Environmental qualification. In its response, the applicant stated that at VYNPS, electrical penetration assemblies are included in the Environmental Qualification Program and are not subject to an AMR. The staff finds that since all electrical and I&C containment assemblies are included in the Environmental Qualification Program, an AMR is not required for electrical and I&C containment
 
assemblies.For uninsulated ground conductors, the applicant stated in plant basis document thatuninsulated ground conductors (e.g., copper and aluminum cable, copper bar, and steel bar) make ground connections for electrical equipment. Uninsulated ground conductors are connected to electrical equipment housing and electrical enclosures as well as metal structuralfeatures such as the cable tray system and building structural steel. Uninsulated ground conductors are always isolated or insulated from the electrical operating circuits. Uninsulated ground conductors enhance the capability of the electrical system to withstand electrical system disturbance (e.g., electrical faults, lightning surges) for equipment and personnel protection.
Non-insulated ground conductors do not support the functions specified in 10 CFR 54.4.Further, the applicant stated that it has reviewed the UFSAR for reference to uninsulated groundconductors and no mention was made of a safety-related function or intended function for license renewal. VYNPS uninsulated ground conductors including grounding rods, buried groundcables, cathodic protection cables, and lightning arresters, are not utilized to support a license renewal function, and are not necessary for response to recovery from an SBO event.
Therefore, the applicant concluded that uninsulated ground conductors are not required an AMR. The staff finds the applicant's assessment and justification that uninsulated ground conductors are not in-scope of license renewal acceptable and therefore not required an AMR.In LRA Table 3.6.1, Item 3.6.1-6, the applicant stated that the fatigue of fuse holders (not part ofa larger assembly) metallic clamp due to ohmic heating, thermal cycling, electrical transients, frequent manipulation, vibration, chemical contamination, corrosion, and oxidation is notapplicable at VYNPS. The applicant also stated that a review of VYNPS documents indicated that fuse holder utilizing metallic clamps are either part of an active device or located in circuits that perform no license renewal intended function. Therefore, fuse holder at VYNPS are not subject to an AMR. In its electrical screening document the applicant stated that VYNPS employs two general type of fuse holders. The first type is the bolt-mount fuse holder that uses either a lug or cap-screws to secure the fuse between the clamps. The second type of fuse holder is the metallic clamp fuse holder, which uses the spring tension. Installation data for 3-493cables and connections indicated that the only fuse holders installed at VYNPS that utilizemetallic clamps to secure the fuse are either part of active assembly or are located in circuits that perform non-license renewal intended functions. The staff asked the applicant to clarify if there was any bolt-mount fuse holder in-scope of license renewal that is not part of an active assembly. In its response, the applicant stated that the two types of fuse holders are all located in active devices. The staff finds the applicant's response acceptable.On the basis that fuse holders are either part of an active assembly or located in circuits thatperform no license renewal intended function, the staff finds that an AMR is not required for fuse holders (insulation and metallic parts) at VYNPS.In LRA Table 3.6.1, Items 3.6.1-7, 8, 9, and 10, the applicant stated that the following GALLReport aging effects of metal enclosed bus (MEB) are not applicable to VYNPS:loosening of bolted connection due to thermal cycling and ohmic heating,embrittlement, cracking, melting, discoloration, swelling, or loss dielectric strength leading to reduced IR; electrical failure due to thermal/thermoxidative degradation of organics/thermoplastic, radiation-induced oxidation; moisture/debris intrusion,ohmic heating, loss of material due to general corrosion, hardening and loss of strength/elastomers degradation. The applicant finds that VYNPS does not have any MEB that supports a license renewalfunction. Therefore, MEB at VYNPS is not subject to an AMR. The staff noted that 10 CFR 54.4(a)(3) requires, in part, that all SSCs relied on in safetyanalyses or plant evaluation to perform a function that demonstrates compliance with the commission's regulations for SBO (10 CFR 50.63) are within the scope of license renewal.
UFSAR Section 8.3.3 for VYNPS stated that electric power is supplied from the transmission network to the onsite electric distribution system by two independent circuits, one immediateaccess and one delayed access. The delay access circuits is available by opening the generatorno-load disconnect switch and establishing a feed from the 345 kV switchyard through the main generator step-up transformer and unit auxiliary transformer to the 4160 V safety buses. The iso-phase buses are used to connect the delay access circuits from the low side of main generator step-up transformer to the high side of unit auxiliary transformer. The staff asked the applicant to clarify why MEBs (iso-phase buses) were not in-scope of license renewal and did not require an AMP.In its response, the applicant stated that UFSAR Section 8.3.3 for VYNPS describes three offsitepower sources: (1) the immediate access circuits from the 345 kV/115 kV auto-transformer to the startup transformers, (2) the alternate immediate access circuits from the 115 kV yard (Keene line) through the startup transformers, and (3) the delayed access circuit which is available by opening the generator no-load disconnect switch and establishing a feed from the 345 kV switchyard through the main and auxiliary transformers. The delayed access circuit from the 345 kV switchyard through the main generator step-up transformer and unit auxiliary transformer uses the iso-phase bus for connection and is within the scope of license renewal.
3-494The applicant committed to develop the MEB program. The VYNPS Metal-Enclosed BusProgram will be added to the following LRA sections:Section 2.5 - Electrical and I&C SystemsSection 3.6 - Electrical and Instrumentation and Controls Table 3.6.1 Table 3.6.2-1 Appendix A Appendix BIn a letter dated October 17, 2006, the applicant revised its LRA. The applicant added LRASections A.2.1.38 and B.1.32 describing its Metal Enclosed Bus Inspection Program. The applicant also included the program basis document that provides the program elements comparison to the GALL Report. This program applies to the isophase bus located between the main transformer and the unit auxiliary transformer. The staff's evaluation of the applicant's Metal Enclosed Bus Inspection Program is documented in SER Section 3.0.3.2.20. The staff finds the applicant's response acceptable because the aging effects of MEB discussed above will be managed by the Metal Enclosed Bus Inspection Program.All SSCs relied on in safety analyses or plant evaluation to perform a function that demonstratescompliance with the commission's regulation for SBO (10 CFR 50.63) must be within the scope of license renewal as required in part by 10 CFR 54.4(a)(3). VHS has been designated as the SBO AAC source and is used to meet SBO requirements of 10 CFR 50.63. During the audit and review, the staff requested the applicant provide an AMR for long-lived, passive SSCs (electrical, mechanical, civil, structures) associated with the hydro station. In its response, the applicant stated that the long-lived, passive components from the Vernon dam switchyard to the plant are in-scope and subject to an AMR. The underground cables and connections are included in E2.
The Vermon dam is regulated by FERC and inspected in accordance with FERC regulations. The staff noted that not all SSCs for the VHS have been included in an AMR. For example, two13.8 kV underground medium voltage cables which connect two step-up transformers 13.8 KV to 69 KV are not included in an AMR. The staff issued RAI 3.6.2.2-N-08 and requested the applicant to provide an AMR for all long-lived, passive SSCs associated with the VHS. In a letter dated July 14, 2006, the applicant stated that:Electrical SSCs for the VHS include the generators associated with each turbine,cables and bus for power transmission, and I&C components and their associated cables and connections. Power from the generators is supplied to the VHS switchyard via two medium-voltage (13.8 kV) underground cables to two independent step-up transformers in the switchyard. Switchyard bus downstream of each step-up transformer feeds the 69kV to 13.2 kV transformer that feeds the Vernon tie breaker. The Vernon tie breaker connects power from the transformer to the 13.2 kV underground cable going to VYNPS. Passive, long-lived components from the breakers feeding the 69 kV to 13.2 kV transformer to and including the 13.2 kV underground cable are included in the AMR for plant electrical and instrument and control systems as described in LRA Sections 2.5 and 3.6. The Vernon tie is a highly reliable connection between the VHS and 3-495either of the two VYNPS 4160 V emergency buses and is capable of supplyingpower to required loads under postulated SBO conditions. Loss of the Vernon tie is annunciated and its voltage is monitored in the VYNPS control room.
Surveillance testing of the Vernon tie demonstrated the ability to energize an emergency bus and supply required SBO loads in less than 10 minutes.
Additionally, the plant is able to safely cope with a total loss of AC power for a minimum of 2 hours from the onset of the SBO to the restoration of offsite AC power. The VHS is designated as a "black-start" facility under arrangements with the regional grid operator. TransCanada has affirmed that they are committed under tariff to provide black-start capability of the VHS to ISO-NE. Both the NEPOOL and REMVEC procedures state that "the most critical power requirement after a blackout is the assurance of reliable shutdowns of nuclear generators, and that expeditious restoration of alternative offsite power sources to nuclear units is imperative to promote the continued reliability of shutdown operations." TransCanada conducts and documents the black-start of the VHS annually. As a backup to local indication available to grid operators of a regional blackout, VYNPS procedures direct operators to immediately contact the regional grid control center to initiate a black start of the VHS if the Vernon tie is unavailable due to a regional grid blackout. The regional grid control center procedures direct hydro-station operators (including the VHS operators) to initiate black start procedures, and upon notification that the units are started, provide instructions to align power to VYNPS and to communicate when these actions are complete to the VYNPS control room. The owner of the VHS has a procedure for the actual black start. The combination of the periodic testing of the AAC sourcetogether with the test of the emergency bus that is conducted every operating cycle encompasses the condition of the SBO event, and provides added assurance of VHS availability to meet the requirement of 10 CFR 50.63. Based on the designation of the TransCanada VHS units as black start units by ISO-NE, the procedural requirements for achieving black start, and the operating history of the VHS units, there is reasonable assurance that a VHS unit will be available within the SBO coping time frame. Consistent with the approach described in LRA Section 2.1.2.3, "Screening of Electrical and Instrumentation and Control Systems," the commodity groups that perform an intended function without moving parts or without a change in configuration) are high-voltage insulators, and cables, connections and electrical busses. Other electrical and I&C commodity groups, including transformers, are active and do not require an AMR. In this letter, the applicant also stated that aging effects requiring management are those thatcan prevent accomplishment of the VHS intended function. Because of the multiple independent generators and power transmission circuits within the VHS, no single component failure due to the effects of aging can prevent accomplishment of the VHS intended function. Therefore, according to the applicant, no aging effects require management for electrical and I&C commodity groups within the VHS. Within the VHS switchyard (owned by National Grid), two circuits provide power to the 69 kV to 13.2 kV transformer that feeds through the Vernon tie breaker to the underground 13.2 kV cable routed to VYNPS. The switchyard bus and associated connections involved with this circuit are subject to an AMR. Aging management review of this portion of the switchyard was addressed in the LRA, Section 3.6, for the SSCs described in LRA Section 2.5 in accordance with "Evaluation Boundaries" on page 2.5-2. Specifically, the path 3-496includes the switchyard circuit breakers near the Vernon Dam that feed the Vernon tietransformer, switchyard bus and insulators, and cables and connections in the circuit to the emergency bus and structures. Two independent paths constitute the remainder of the circuit that provides power from the VHS to the VHS switchyard. Because of the two independent power transmission circuits, no single component failure due to the effects of aging can prevent accomplishment of the VHS intended function. Therefore, there are no aging effects requiring management for this portion of the circuit. Availability of the Vernon tie line is tracked on a three-year rolling basis. Over the last 4 years, the line has been available 99.32 percent of the time. Approximately 60 percent of the unavailability was due to the planned replacement of the 4kV underground cable between the 13.2 kV / 4.16kV transformer and the VYNPS 4.16 kV buses. This operating experience indicates the effectiveness of routine switchyard maintenance in achieving acceptable performance of the switchyard circuit between VHS and VYNPS.
 
The staff noted that the applicant's July 14, 2006 response stated that no aging effects require management for VHS based on independent generators and power transmission circuits.
However, the statement of considerations to 10 CFR Part 54 states that redundancy can not be used to preclude aging effects of in-scope passive long-lived electrical components. In order for the staff to further evaluate the VHS issue, the staff requested that the applicant in RAI 3.6.2.2-N-08-2, to provide additional information regarding the electrical SSCs for the VHS including 2 black-start turbine generators, cables and buses for power transmission, and I&C components and their associated cables and connections. The staff noted that the applicant's Non-EQ Inaccessible Medium-Voltage Cable Program addressed the underground cables fromVernon tie breaker routed to VYNPS. However, the rest of the SBO SCs were not included in any AMP and thus their performance could not be reasonable assured.In response to the staff's RAI 3.6.2.2-N-08-2, in a letter dated October 20, 2006, the applicantstated:The Statement of Considerations required by 10 CFR Part 54 clearly states thatcrediting regulatory required redundancy as a surrogate for an agingmanagement program is inappropriate."Further, the Commission believes that crediting a regulatory requirement (i.e.,redundancy) [emphasis added] as a surrogate for an aging management programto ensure a system's intended function exploits the Commission's defense-in-depth philosophy." (SOC, Section V. Public Response to Specific Questions)The applicant stated that it is inappropriate to generically exclude in-scope passive long-livedelectrical components from an AMR based solely on required redundancy. However, the multiplegenerators and circuits associated with the VHS constitute a unique configuration different than that addressed by the required redundancy discussion in the SOC. That is, the VHS designincorporates redundancy that is not required by regulations. The applicant also stated that unlike many typical SBO AAC sources, the VHS and portions ofthe VHS switchyard associated with the SBO AAC source operate continuously. Most SBO AAC sources, such as diesel generators or gas turbine generators, operate in standby service.
According to the applicant, the fact that the generators and associated electrical circuits 3-497continuously operate provides verification that they remain capable of performing their licenserenewal intended functions under CLB conditions because no single failure due to the effects of aging can prevent the VHS from fulfilling its license renewal intended function of maintaining greater than 95 percent availability.The applicant stated that an AMP is not necessary for the electrical components from the VHSgenerators to the Vernon Tie breaker and that operating experience confirms this conclusion.
Historically, VHS reliability has exceeded the reliability specified in guidance documents formeeting the SBO rule, specifically, the 95 percent availability specified in NUMARC 87-00. Infact, historical availability far exceeds that expected from a more typical auxiliary diesel generator or combustion turbine generator. Additionally, the applicant stated that the following ongoing activities provide additional assurance that the SBO AAC source remains capable of performing its license renewal intended function.  (1)The VHS owner plans to replace the medium-voltage underground cable from the VHSpowerhouse to the switchyard. This work is scheduled to be performed in the coming year. Only 26 years of operation remain for VYNPS between now and the end of the period of extended operation. Though not formally qualified, modern underground cables are expected to have a service life of greater than 26 years.  (2)The switchyard owner utilizes thermography on a periodic basis to ensure continuedreliable switchyard performance.The applicant also stated in a report that VHS with multiple units, has demonstrated reliability farin excess of an auxiliary generator (99.9 percent compared to 95 percent). Subsequent to 1994, the VHS has continued to demonstrate very high availability. The VHS remained on line throughout the Northeast blackout of August 14, 2003. Both long-term and recent operating experience confirms that normal operation provides reasonable assurance that the VHS will remain capable of performing its intended function in accordance with the CLB throughout the period of extended operation. Notwithstanding the above, VYNPS will monitor the availability of the VHS to ensure continued capability to perform its license renewal intended function, that is, conformance with the availability specified in NUMARC 87-00 for meeting the requirements of the SBO rule. If availability falls below the acceptable level, VYNPS will respond to the condition through the CAP. The CAP requires evaluation and appropriate corrective action to correct the nonconforming condition.The staff finds the applicant's response unacceptable. The SOC to 10 CFR Part 54 states thatredundancy can not be used to generically exclude aging effects for in-scope passive long-lived electrical components. Aging can occur at different rates on redundant trains. Similarly, operating experience and reliability of VHS can not be used to preclude aging effects of in-scope passive long-lived electrical components in VHS. The applicant argued that redundancy of transmission circuits, operating experience, and reliability of VHS preclude an AMR. Regarding the redundance argument, the staff noted that the reason the -redundancy cannot be used to preclude an AMR is that when an SSC is subject to an aging affect, no matter how much redundancies an SSC has, aging will affect all redundant paths/circuits and common cause 3-498failures and may prevent them from performing their intended functions. On this basis, the staffconcludes that redundancy cannot be used to preclude an AMR. The staff finds that the applicant did not provide an adequate technical justification of how aging effects of in-scope long-lived electrical components from Vernon tie breaker to VHS generators will be managed during the extended period of operation. In a letter dated January 4, 2007, License Renewal Application, Amendment 23, the applicantprovided additional clarification to address RAI 3.6.2.2-N-08-2. Specifically, the applicant stated: The switchyard owner utilizes thermography on a periodic basis to ensurecontinued reliable switchyard performance. To further address the electrical component from the tie breaker to VHS generators, the following describes how aging effects on the VHS switchyard electrical components will be managed during the period of extended operation.The design of the transmission conductor and switchyard bolted connectionspreclude the aging effect of increased connection resistance due to torque relaxation. The typical design of switchyard bolted connections includes Bellville washers and no-ox coating. The type of bolting plate and the use of Bellville washers is the industry standard. Combined with the proposer sizing of the conductors, this virtually eliminates the need to consider this aging effect. The switchyard owner performs infrared inspection of the VHS switchyard connections at least annually. Based on this information, increased connection resistance due to torque relaxation of transmission connections is not a significant aging effect.
Therefore, increased connection resistance of VHS switchyard connections does not require an AMP at VYNPS. Thermal infrared inspection was performed at the VHS substation on 10/06/06and there were no abnormalities found.Loss of material due to corrosion of connections or surface oxidation is anapplicable aging effect, but is not significant enough to cause a loss of intended function. The components in the VHS switchyard are exposed to precipitation, but these components do not experience an appreciable aging effect in this environment, except for minor oxidation, which does not impact the ability of the connections to perform their intended function. The VHS switchyard connection surfaces are coated with an anti-oxidant compound (i.e., a grease-type sealant) prior to tightening the connection to prevent the formation of oxides on the metal surface and to prevent moisture from entering the connections thus reducing the chances of corrosion. Based on industry operating experience, the method of installation has been shown to provide a corrosion resistant low electrical resistance connection. In addition, the infrared inspection of the VHS switchyard verifies that this is not a significant aging effect for VYNPS. Therefore, it is concluded that general corrosion resulting from oxidation of VHS switchyard connection surface metals is not an AERM at VYNPS.
3-499The staff finds that the applicant's clarification is acceptable because the design of transmissionconnections using Bellville washers will eliminate the potential torque relaxation of bolted connections. Anti-oxidant compound will prevent the formation of oxides on the metal surface and to prevent moisture entering the connections thus reducing the chances of corrosion. In addition, routine infrared preventive maintenance is performed at least annually to verify the integrity of switchyard connections. On the basis of its review, the staff finds the applicant's response to RAI 3.6.2.2-N-08-2 is acceptable. The staff finds that aging effects of in-scope long-lived electrical components from Vernon tie breaker to VHS generators are not significant during the period of extended operation and an AMP is not required. Therefore, the staff's concern described in RAI 3.6.2.2-N-08-2 is resolved.In RAI 3.6.2.2-N-08-3, the staff requested that the applicant identify all inaccessiblemedium-voltage (2 kV to 35 kV) cables associated with SBO AAC source from the VHS generators to 4.16 kV safety buses at VYNPS. The staff also requested that the applicant provide a description of how aging effects are managed for all inaccessible medium-voltage cables associated with SBO AAC that are exposed to moisture while energized and are not subject to Environmental qualification requirements of 10 CFR 50.49 and provide a description of how these cables will be maintained through the period of extended operation. In response to the staff's RAI 3.6.2.2-N-08-3, in a letter dated October 20, 2006, the applicantstated:Inaccessible medium-voltage cables associated with SBO AAC source from theVHS generators to 4.16 kV safety buses at VYNPS include the underground cable from the Vernon tie breaker to the Vernon tie transformer, the underground cable from the Vernon tie transformer to the 4.16kV switchgear, and the underground cable between the VHS switchyard and the VHS generators. The medium voltage underground cables from the Vernon tie breaker to the 4.16kV switchgear at VYNPS are in-scope and will be managed by the Non-Environmental Qualification Medium-Voltage Cable Program described in LRA Appendix B. The medium-voltage underground cables from the VHS generators to the VHS switchyard comprise two independent power circuits between the VHS powerhouse and the step-up transformers in the VHS switchyard. Because of the two independent power circuits, the effects of aging will not result in loss of the intended function of the VHS. Failure of a cable due to the effects of aging will be detected and repaired during normal operation without impacting the ability of the VHS to perform its intended function. The applicant also stated that the design incorporates redundancy beyond that required for AAC sources. The SBO rule does not require redundancy of the AAC source. Because of this unique configuration, the fact that the generators and associated electrical circuits are operating is verification that they remain capable of performing their license renewal intended functions under CLB conditions.The staff noted that the purpose of aging management is to prevent a loss of intended functionof a SSC. When a SSC is subject to an aging mechanism, it may not perform its intended function when called upon during a design basis accident. Loss of function due to an aging effect would likely take a long time. Sometimes, aging effects would not show as an immediate indication of problem with the equipment or circuit and are not considered an event. The staff 3-500disagrees with the applicant's argument that redundancy and normal operation of VHS precludean AMP for inaccessible medium-voltage cables from VHS generators to the VHS switchyard.
The staff is concerned that these cables are subjected to significant moisture and water intrusion while energized and may not perform their intended function of providing an AAC source during an SBO, thus ensuring that the reactor can be safely shutdown.In a letter dated January 4, 2007, the applicant provided additional information forRAI 3.6.2.2-N-08-3. Specifically, the applicant stated: As stated in LRA Section 2.5, VYNPS uses the VHS as an AAC source to satisfythe requirements of 10 CFR 50.63 for response to a SBO. LRA Section 2.5 lists the electrical commodity groups that are subject to an AMR, and non-Environmental qualification inaccessible medium-voltage cables are included.LRA Section 3.6 provides the results of the AMR. Moisture and voltage stress is an applicable environment, and the "Non-Environmental Qualification Inaccessible Medium-Voltage Cable" program manages the aging effect of reduced insulation resistance.Previous RAI and audit question responses stated that the VHS undergroundmedium-voltage cables do not have aging effects that require management.Reduced insulation resistance due to moisture and voltage stress is an agingeffect for underground medium-voltage cables, but is not significant enough to cause a loss of intended function. The underground cables in the VHS switchyard are exposed to similar environments as the VYNPS underground cables. The VHS underground medium-voltage cable is scheduled to be replaced by the National Grid (TransCanada) in 2007.The cable planned for installation between the VHS generator and the VHSswitchyard is similar to the VYNPS startup transformer to 4160 V switchgear
 
cable. aBoth have ethylene-propylene rubber (EPR) insulation at a 133 %insulation level. bThe VHS cable has specified a chloro-sulfonated polyethylene jacket. PerNEI 06-05 April 2006, "Medium Voltage Underground Cable White Paper,"
these jackets provide excellent moisture barriers. This jacket material is equal to or better than the VYNPS jacket. cBoth cables are installed in buried conduit, with a similar physicalconfiguration (e.g., start at an elevated external connection, vertical conduit to the underground conduit, which is a slopped horizontal conduit that penetrates the connecting building). dVHS and VYNPS are located approximately one-quarter of a mile to eachother, so they experience identical environmental conditions. Even though the VHS switchyard is closer to the river and lower in elevation than 3-501VYNPS and because the VHS switchyard is located downstream of theVHS, the water table is at a similar level to VYNPS. eBoth cables utilize red or pink EPR insulation, as black EPR productionended in the 1970's. The newer EPR insulation has treated clay fillers to preclude water absorption making the insulation less prone to water degradation than the older black EPR formulations. NEI 06-05 April 2006, "Medium Voltage Underground Cable White Paper" indicates strong performance of red EPR and notes that early EPR failures were due to installation practices. fConsidering:ii.VHS will install this cable next year.
iii.The proposed extended operation ends in 25 years(March 2032)The observed good performance of red EPR cable to date for the industryindicated at least 25 to 30 years of cable life, which will extend beyond the VYNPS period of extended operation. Based on the similarities of the cables, VYNPS proposed to credit testing ofstartup transformer cables (which are already in-scope) as an alternate method for verifying the VHS cable will continue to perform its intended function during the period of extended operation. This is considered equal or more stringent because of the following:  aThe VYNPS cable will have been installed for 3 years longer than the VHScable providing a leading indicator for the VHS cable. bThe startup transformer cable is loaded intermittently, and the VHS cableis continuously loaded. As such, the VHS cable insulation heating is more even and changes slowly, and therefore dries the cable insulation with fewer electrical transients (cycles). Therefore the startup transformer environment is more severe from this perspective. cNEI 06-05, April 2006, "Medium Voltage Underground Cable WhitePaper," Page 1 noted that EPR tends to have a long service life (> 25 years) in wet applications and an even longer service in dry environments. dIf an issue is found during testing of the VYNPS cables, VYNPS willdocument and address the condition through the Entergy CAP. Corrective actions will include an evaluation to determine the appropriate action to ensure the VHS cables remain capable of performing their intended function.
3-502The VYNPS AMP for the underground medium-voltage from the VHS generatorsto the VHS switchyard will be similar to the NUREG-1801, XI.E3 program, but will have an exception. The XI.E3 program provides for 100 % testing of all cables included in the program. The exception for the VHS cables will use a representative sample, and the sample population will include the VYNPS cables.
The VYNPS cables will be included in XI.E3 program, but the program will use the test results of similar VYNPS cables installed between the startup transformer and the station 4160V switchgear to indicate any potential degradation of the VHS
 
cables.The staff finds that the applicant's proposal is unacceptable. Testing of VYNPS cables will notrepresent the actual condition of VHS underground cables. The environmental condition of cables at VYNPS and VHS is different. VHS is located closer to the river than VYNPS. VYNPS is located approximately one-quarter of a mile from VHS. VHS cables are installed in lower elevation than VYNPS's cables. The ground water level at VHS is higher than at VYNPS. VHS cables are installed in buried conduit with no manholes. Inspection and removal of water are difficult. Testing of VYNPS cables would not represent the actual condition of cables at VHS.Furthermore, TransCanada owns VHS, not VYNPS. Even if an issue was found during testing of VYNPS cables, there is no binding contractual agreement between VYNPS and TransCanada for TransCanada to take appropriate corrective action for VHS cables. Operating experience has shown that inaccessible medium-voltage cables installed in duct banks, conduits, or buried in dirtmay fail earlier than the cable qualified life. The GALL Report recommends testing all inaccessible medium-voltage cables within the scope of license renewal prior to the period ofextended operation for cable condition and every 10 years thereafter. The staff position is that testing is not required for cables designed for submerged use (submarine cables) only. The issue of testing inaccessible medium-voltage cables from VHS generators to VHS switchyardremains open.In response to the staff's concerning about not testing inaccessible medium cables at VHS, theapplicant, in a letter dated March 23, 2007, revised LRA Table 3.6.2-1 and stated that VYNPS will include testing of the underground medium-voltage cables at VHS in the Non-EQ Inaccessible Medium-Voltage Cable Program. Testing will be performed before the extended operation and within 10 -year periods after the initial test. This is Commitment #43. The staff found the applicant's response acceptable because testing of inaccessible mediumvoltage cables at VHS will ensure that aging effects of inaccessible medium-voltage due to significant moisture will be managed during the extended period of operation. The staff's evaluation of this program is SER Section 3.6.2.1. On the basis of its review, the staff determines the applicant's response to RAI 3.6.2.2-N-08-3 acceptable. Therefore, the staff's concern described in RAI 3.6.2.2-N-08-3 is resolved.In RAI 3.6.2.2.N-08-4, the staff requested the applicant to address the following:The applicant has stated that VHS switchyard passive long-lived commodity groups areeffectively maintained through routine maintenance by the switchyard owner. Describe this routine maintenance and how it considers aging management of the VHS switchyard passive long-lived commodity groups.
3-503In response to the staff's request, in a letter dated October 20, 2006, the applicant stated:Normal operation confirms these components remain capable of performing theirintended functions. In addition, because of the two independent power transmission circuits, the effects of aging will not result in loss of the intended function of the VHS. Failure of a cable due to aging will be detected and repaired during normal operation without impacting the ability of the VHS to perform its intended function. Note that the design incorporates redundancy beyond that required for AAC sources. The SBO rule does not require redundancy of the AAC source. Because of this unique configuration, the fact that the generators and associated electrical circuits are operating is verification that they remain capable of performing their license renewal intended functions under CLB conditions. The staff noted that the applicant again used the redundancy features to address the AMR forelectrical components. As discussed above, the staff does not find this argument acceptable. If thermography is used on a periodic basis to detect heating generated by high resistance of switchyard components due to aging effects of oxidation, corrosion, and thermal cycling, this method can be credited to manage the aging of the switchyard component. An applicant that does not believe that aging management is necessary, must provide justification for why an AMP is not necessary. The justification should be technically based and not based on redundancy, operability, and reliability. In a letter dated January 4, 2007, the applicant provided additional clarification forRAI 3.6.2.2.N-08-4. Specifically, the applicant stated that the switchyard owner utilizes thermography on a periodic basis (at least annually) to provide additional assurance of continued reliable switchyard performance. On the basis of its review, the staff finds that the applicant's response to RAI 3.6.2.2-N-08-4 isacceptable. The staff concludes that thermography performed on a periodic basis (at least annually) is a good method to detect heating generated by potential high resistance of switchyard components due to oxidation, and corrosion. Therefore, the staff's concern described in RAI 3.6.2.2-N-08-4 is resolved.In RAI 3.6.2.2-N-08-5, the staff requested that the applicant addresses the following items as itrelated to SBO AAC:  (a)Please describe (as stated in GALL XI.E6) how aging effects are managed so that theintended function of cable connections associated with SBO AAC (including VHS) will be maintained during the extended period of operation.    (b)As stated in GALL XI.E5, fuse holders that are within the scope of license renewal shouldbe tested. Provide an AMR and describe how aging effects are managed for fuse holders (metallic clamps) associated with SBO AAC source (including VHS).  (c)Provide a discussion why torque relaxation for bolted connections of switchyard buswithin the VHS switchyards (69 kV and 13.8 kV) is not a concern.
 
3-504  (d)Per LRA 3.6, increased resistance of connections due to oxidation is not an applicableaging effect. Provide a discussion as to why increased resistance of connections due to oxidation is not a concern for switchyard bus and switchyard bus connections associated with VHS switchyards.  (e)A large buildup of contamination enables the conductor voltage to track along the surfacemore easily and can lead to insulator flash over. Please describe how aging effects are managed for high-voltage insulators within the VHS switchyards.In response to the staff's request for RAI 3.6.2.2-N-08-5(a), in a letter dated October 20, 2006,the applicant stated that:Two groups of components constitute the electrical components associated withthe SBO AAC source for VYNPS. One group consists of components on the plant side of the Vernon tie breaker. This group of components is included in the evaluation of plant electrical equipment. Aging effects and aging management programs are common with other plant electrical equipment. The second group consists of components between the VHS generators and the Vernon tie breaker.
This group of components is not owned or controlled by Entergy. Metallic parts of electrical cable connections that are exposed to thermal cyclingand ohmic heating are those carrying significant current in power supply circuits.
Cable connections for the SBO AAC source at the VHS are associated with redundant power circuits with the exception of a small part of the circuit that feeds the step-down transformer upstream of the Vernon tie. This part of the switchyard is normally energized supplying power to local consumers. Normal operation confirms availability of the circuit to perform its license renewal intended function.
The fast action of circuit protective devices at high currents mitigates stresses associated with electrical faults and transients. In addition, mechanical stressassociated with electrical faults is not a credible aging mechanism because of thelow frequency of occurrence for electrical faults. Therefore, electrical transients are not aging mechanisms. Metallic parts of electrical cable connections exposed to vibration are those associated with active components that cause vibration.
Active components are not subject to an AMR in accordance with 10 CFR 54.21.
In addition, connections required for the SBO AAC source are not associated with rotating equipment that causes vibration. Routine releases of corrosive chemicalsto areas inside VHS or the associated switchyard do not occur. Corrosive chemicals are not a normal environment for electrical connections. Contamination of electrical connections causes rapid degradation independent of the age of the connection components. Corrosion due to contamination is due to the contamination event rather than aging. Therefore, chemical contamination is not an aging mechanism for electrical connections. Corrosion and oxidation occur in the presence of moisture or contamination such as industrial pollutants and salt deposits. Enclosures and splice materials protect metal connections from moisture and contamination. In addition, the VHS is not located in an area of significant industrial pollution or near seawater with the potential for salt spray.
Therefore, oxidation and corrosion are not applicable aging mechanisms for cable connections. The mechanisms discussed above are not applicable aging 3-505mechanisms for the SBO AAC source. In addition, normal operation of the VHScircuit components confirms the capability to perform license renewal intended functions. Therefore, no aging management program is necessary for connections. This conclusion is supported by the long history of reliable operation of the Vernon tie line.On the basis of its review of the applicant's response, the staff determined that the applicant'sresponse was not acceptable. Connections are passive components and in-scope of license renewal. Loosening of bolted connections is an aging effect which must be managed. Thermal cycling, ohmic heating, electrical transients, vibrations, chemical contamination, corrosion, andoxidation are aging mechanisms. Connections associated with cables in-scope of license renewal are part of this program, regardless of their association with active or passive components. Cable lugs are an integral part of cables. Integrity of lugs can be verified by testing connections. GALL AMP XI.E1 manages connections in adverse locations only and inspects insulation degradation. Most connections are not located in adverse locations. SAND 96-0344, "Aging Management Guidelines For Electrical Cable and Terminations," indicated looseterminations were identified by several plants. EPRI-TR-104213, "Bolted Joint Maintenance &
Application Guide," indicates that it is difficult to maintain tightness of electrical connections and good conductivity through a large temperature range if the materials for the bolt connections and conductors are different and have different rates of thermal expansion. For example, copper and aluminum expand faster than most bolting materials. The staff was not aware of any action taken to manage the aging effects of cable connections. As discussed in the GALL Report basis document, several applicants reported loose connections due to corrosion, vibration, thermal cycling, etc. Also, past applicants have been using thermography to detect weak/loose connections and correct them as soon as possible and provided an AMP consistent with GALL AMP XI.E6 to manage aging effects of bolted connections. In a letter dated January 4, 2007, the applicant provided additional information forRAI 3.6.2.2-N-08-5(a). The applicant proposed a one-time inspection of a representative of cable connections subject to an AMR. This AMP for electrical cable connections (metallic parts)accounts for loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation. However, the applicantdid not mention if the Bolted Cable Connections Program will be applicable to VHS cable connections. The staff requested the applicant to clarify if this AMP is applicable to VHS. The applicant stated that it will provide additional clarification to LRA Table 3.6.1, Item 3.6.1-13.
Specifically, the following will be added to the discussion column of LRA Table 3.6.1, Item 3.6.1-13-: "SBO Connections (Vernon tie cable connections) are included in Bolted Cable Connections Program."By letter dated January 4, 2007 the applicant added to the discussion column of LRATable 3.6.1, Item 3.6.1-13: "SBO Connections (Vernon tie cable connections) are included in Bolted Cable Connections Program." On the basis of its review, the staff finds the applicant's response to RAI 3.6.2.2-N-08-5(a)acceptable because the applicant included the SBO connection in its Bolted Connection Program. Therefore, the staff's concern described in RAI 3.6.2.2-N-08-5(a) is resolved.
3-506In response to the staff's request in RAI 3.6.2.2-N-08(b), in a letter dated October 20, 2006, theapplicant stated that review of VYNPS documents for the SBO AAC source at VHS revealed that fuse holders that utilize metallic clamps are part of active devices and therefore are not subject to an AMR. Fuse holders inside enclosures of active components, such as switchgear, power supplies, power inverters, battery chargers, and circuit boards, are parts of the larger active device, and are not subject to an AMR. On the basis of its review, the staff finds the applicant's response to RAI 3.6.2.2-N-08(b)acceptable. The staff concludes that fuse holders at VHS SBO AAC source are part of an active assembly and are not subject to an AMR. Therefore, the staff's concern described in RAI 3.6.2.2-N-08(b) is resolved.In response to the staff's request in RAI 3.6.2.2-N-08(c), in a letter dated October 20, 2006, theapplicant stated that:The VHS switchyard employs an aerial cable system (transmission conductorssuspended by insulators with vertical taps). Cable connections for the SBO AAC source at the VHS include some bolted connections that are not part of active components. Cable connections for the SBO AAC source at the VHS are associated with redundant power circuits with the exception of a small part of the circuit that feeds the step-down transformer upstream of the Vernon tie. This part of the switchyard is normally energized supplying power to local consumers.
Normal operation of the switchyard confirms the ability of these connections to perform their license renewal intended function. The historically high availability of the SBO AAC source demonstrates the effectiveness of normal operation in assuring the ability of the associated connections to perform their license renewal intended function.The applicant stated that redundancy and normal operation preclude an AMR for cableconnections at the VHS switchyard. The SOC to 10 CFR Part 54 states that required redundancy can not be used to preclude aging effects of in-scope passive long-lived electrical components. Torque relaxation for bolted connections is a concern for switchyard cable connections. An electrical connection must be designed to remain tight and maintain good conductivity through a large temperature range. Meeting this design requirement is difficult if the material specified for the bolt and the conductor are different and have different rates of thermal expansion. For example, copper or aluminum bus/conductor materials expand faster than most bolting materials. If thermal stress is added to stresses inherent at assembly, the joint members or fasteners can yield. If plastic deformation occurs during thermal loading (i.e., heatup) when the connection cools, the joint will be loose. EPRI document TR-104213, "Bolted Joint Maintenance & Application Guide," recommends inspection of bolted connections for evidence of overheating, signs of burning or discoloration, and indication of loose bolds. The determined that the applicant has not provided an acceptable technical justification that an AMP is not required for cable connections at VHS switchyard. Therefore, the staff's concern in RAI 3.6.2.2-N-08-5(c) remained unresolved.
3-507In a letter dated January 4, 2007, the applicant provided additional clarification forRAI 3.6.2.2-N-08-5(c). Specifically, the applicant stated:The design of the transmission conductor and switchyard bus bolted connectionspreclude the aging effect increased connection resistance due to torque relaxation. The typical design of switchyard bolted connections includes Bellville washers and no-ox coating. The type of bolting plate and the use of Bellville washers is the industry standard. Combined with the proposer sizing of the conductors, this virtually eliminates the need to consider this aging effect. The switchyard owner performs infrared inspection of the VHS switchyard connections at least annually. Based on this information, increased connection resistance due to torque relaxation of transmission connections is not a significant aging effects.
Therefore, increased connection resistance of the VHS switchyard connections does not require an AMP at VYNPS. Thermal infrared inspection was performed at the VHS substation on 10/06/06with no abnormalities found.The staff finds that the applicant's response is acceptable because the design of transmissionconnections using Bellville washer will eliminate the potential torque relaxation of bolted connections. In addition, routine infrared preventive maintenance is performed at least annually to verify the integrity of switchyard connections. The staff finds that torque relaxation of VHS switchyard connections are not significant during the extended period of operation and an AMP is not required. Therefore, the staff's concern described in RAI 3.6.2.2-N-08(c) is resolved.In response to the staff's request in RAI 3.6.2.2-N-08-5(d), the applicant stated that:NUREG-1801 defines switchyard bus as the uninsulated, unenclosed, rigidelectrical conductor or pipe used in switchyards and switching stations to connect two or more elements of an electrical power circuit, such as active disconnect switches and passive transmission conductors. The VHS switchyard employs an aerial cable system (transmission conductors suspended by insulators with vertical taps). No switchyard bus is used in the Sections of the VHS switchyard that support the SBO AAC source. Normal operation of the switchyard confirms the ability of the aerial cable system to perform its license renewal intended function. The historically high availability of the SBO AAC source demonstrates the effectiveness of normal operation in assuring the ability of the switchyard components to perform their license renewal intended function.As discussed above, redundancy, normal operation or operating experience cannot be used topreclude an AMR. Corrosion of cable connections at VHS switchyard is a concern. Thiscorrosion could create high heat in cable system due to high resistance and could potentially fail the cable system in VHS switchyard. The staff determined that the applicant has not provided a justification of why corrosion of electrical conductor connections is not an aging effect requiring management.
3-508In a letter dated January 4, 2007, License Renewal Application, Amendment 23, the applicantprovided additional clarification to RAI 3.6.2.2-N-08-5(d). Specifically, the applicant, in its letter, stated:Loss of material due to corrosion of connections or surface oxidation is anapplicable aging effect, but is not significant enough to cause a loss of intended function. The components in the VHS switchyard are exposed to precipitation, but these components do not experience an appreciable aging effect in this environment, except for minor oxidation, which does not impact the ability of the connections to perform their intended function. The VHS switchyard connection surfaces are coated with an anti-oxidant compound (i.e., a grease-type sealant) prior to tightening the connection to prevent the formation of oxides on the metal surface and to prevent moisture from entering the connections thus reducing the chances of corrosion. Based on industry operating experience, the method of installation has been shown to provide a corrosion resistant low electrical resistance connection. In addition, the infrared inspection of the VHS switchyard verifies that this is not a significant aging effect for VYNPS. Therefore, it is concluded that general corrosion resulting from oxidation of VHS switchyard connection surface metals is not an AERM at VYNPS.The staff finds that the applicant's response is acceptable because the anti-oxidant compoundprevents the formation of oxides on the metal surface and prevents moisture from entering the connections, thus reducing the chances of corrosion. In addition, routine infrared preventive maintenance is performed at least annually to verify the integrity of switchyard connections. On the basis of its review, the staff finds the applicant's response to RAI 3.6.2.2-N-08-5(d)acceptable and concludes that loss of material due to corrosion of connections or surface oxidation is not significant during the extended period of operation and an AMP is not required.
Therefore, the staff's concern described in RAI 3.6.2.2-N-08-5(d) is resolved.In response to staff's request in RAI 3.6.2.2-N-08-5 (e), in a letter dated October 20, 2006,License Renewal Application, Amendment No. 17, the applicant stated that:Various airborne materials such as dust, salt and industrial effluents cancontaminate insulator surfaces. The surface contamination is typically washed away by rain. Surface contamination can be a problem in areas where there are greater concentrations of airborne particles such as near facilities that discharge soot or near the seacoast where salt spray is prevalent. In those areas, surface contamination buildup can occur in a matter of hours in the event of the right weather conditions. The VHS switchyard is not located near the seacoast where salt spray is applicable. At VYNPS, surface contamination buildup on high-voltage insulators is not a problem since rain removes surface contamination preventing accumulation. Cement growth is a possible aging mechanism for high-voltage insulators used in strain applications. No high-voltage insulators in the VHS switchyard are used in a strain application. Therefore, surface contamination and 3-509cement growth are not applicable degradation mechanisms for high-voltageinsulators at the VHS and associated switchyard. In addition, normal operation of the switchyard confirms the ability of the insulators to perform their license renewal intended function. The historically high availability of the SBO AAC source demonstrates the effectiveness of normal operation in assuring the ability of the associated insulators to perform their license renewal intended function.The applicant also stated that various airborne materials such as salt deposit in coastal areas aswell as dust and industrial effluents can contaminate insulator surfaces. The buildup of surface contamination is gradual and in most areas such contamination is washed away by rain; the glazed insulator surface aids this contamination removal. However, a large buildup of contamination enables the conductor voltage to track along the surface more easily and can lead to insulator flashover. Surface contamination can be a problem in areas where there are greater concentrations of airborne particles such as near costal area or facilities that discharge soot.
Since VHS is not located near a coastal area or near industrial effluents area, there are no aging effects requiring management for VHS high-voltage insulators. The staff finds that degradation of insulator quality due to presence of any salt deposits andsurface contamination, and cement growth are not an applicable aging effects requiring management since VHS are not located near a costal area or near an industrial effuents area.
On the basis of its review, the staff finds the applicant's response to RAI 3.6.2.2-N-08-5 (e) acceptable. Therefore, the staff's concern described in RAI 3.6.2.2-N-08-5 (e) is resolved.
Conclusion. On the basis of its review, the staff finds that the applicant appropriately evaluatedthe AMR results involving material, environment, AERMs, and AMP combinations that are not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.6.3  ConclusionThe staff concludes that the applicant has provided sufficient information to demonstrate that theeffects of aging for the electrical and I&C system components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-5103.7  Conclusion for Aging Management Review ResultsThe staff reviewed the information in LRA Section 3, "Aging Management Review Results," andLRA Appendix B, "Aging Management Programs and Activities." On the basis of its review of the AMR results and AMPs, the staff concludes, that the applicant has demonstrated that the aging effects will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the applicable UFSAR supplement program summaries and concludes that the supplement adequately describes the AMPs credited for managing aging, as required by 10 CFR 54.21(d).With regard to these matters, the staff concludes that there is reasonable assurance that theapplicant will continue to conduct the activities authorized by the renewed license will continue tobe conducted in accordance with the CLB, and any changes made to the CLB, in order to comply with 10 CFR 54.21(a)(3), are in accordance with the Atomic Energy Act of 1954, as amended, and NRC regulations.
4-1 SECTION 4TIME-LIMITED AGING ANALYSES4.1  Identification of Time-Limited Aging AnalysesThis section of the safety evaluation report (SER) addresses the identification of time-limitedaging analyses (TLAAs). In license renewal application (LRA) Sections 4.2 through 4.7, Entergy Nuclear Operations, Inc. (ENO or the applicant) addressed the TLAAs for Vermont Yankee Nuclear Power Station (VYNPS). SER Sections 4.2 through 4.8 document the review of the TLAAs conducted by the staff of the United States (US) Nuclear Regulatory Commission (NRC)
(the staff).TLAAs are certain plant-specific safety analyses that involve time-limited assumptions defined bythe current operating term. In accordance with Title 10, Section 54.21(c)(1), of the Code ofFederal Regulations (10 CFR 54.21(c)(1)), applicants must list TLAAs as defined in10 CFR 54.3.In addition, as required by 10 CFR 54.21(c)(2), applicants list plant-specific exemptions grantedin accordance with 10 CFR 50.12 based on TLAAs. For any such exemptions, the applicant must evaluate and justify the continuation of the exemptions for the period of extended operation.4.1.1  Summary of Technical Information in the ApplicationTo identify the TLAAs, the applicant evaluated calculations for VYNPS against the six criteriaspecified in 10 CFR 54.3. The applicant indicated that it had identified the calculations and analyses meeting the six criteria by searching the current licensing basis (CLB), which includes the updated final safety analysis report (UFSAR), engineering calculations, technical reports, engineering work requests, licensing correspondence, and applicable vendor reports. LRA Table 4.1-1, "List of VYNPS TLAA and Resolution," lists the applicable TLAAs:
* reactor vessel neutron embrittlement analyses
* metal fatigue analyses
* Environmental qualification analyses for electrical components
* containment liner plate, metal containment, and penetrations fatigue analyses
* reflood thermal shock of the reactor vessel internals
* BWRVIP-05, RPV circumferential welds analysis
* BWRVIP-25, core plate rim hold-down bolts loss of preload analysis
* BWRVIP-38, shroud support fatigue analysis
* BWRVIP-47, lower plenum fatigue analysis
* BWRVIP-48, vessel ID diameter attachment welds fatigue analysis
* BWRVIP-49, instrument penetrations fatigue analysis
* BWRVIP-74, reactor vessel
* BWRVIP-76, core shroud 4-2In compliance with 10 CFR 54.21(c)(2), the applicant stated that it had not identified exemptionsgranted in accordance with 10 CFR 50.12, based on a TLAA, as required by 10 CFR 54.3.4.1.2  Staff EvaluationLRA Section 4.1 lists the VYNPS TLAAs. The staff reviewed the information to determinewhether the applicant has provided sufficient information to comply with10 CFR 54.21(c)(1) and (2).To comply with 10 CFR 54.3, TLAAs must meet the following six criteria:
  (1)involve systems, structures, and components within the scope of license renewal, asrequired by 10 CFR 54.4(a)  (2)consider the effects of aging (3)involve time-limited assumptions defined by the current operating term (40 years)
  (4)are determined to be relevant by the applicant in making a safety determination (5)involve conclusions, or provide the basis for conclusions, related to the capability of thesystem, structure, and component to perform its intended functions, as required by 10 CFR 54.4(b)  (6)are contained or incorporated by reference in the CLBThe applicant listed common TLAAs from US NRC NUREG-1800, Revision 1, "Standard ReviewPlan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR), dated September 2005. The applicant listed TLAAs applicable to VYNPS in LRA Table 4.1-1.To comply with 10 CFR 54.21(c)(2), the applicant must list all exemptions granted in accordancewith 10 CFR 50.12, based on TLAAs, and evaluated and justified for continuation through the period of extended operation. The LRA states that each active exemption was reviewed to determine whether it was based on a TLAA. The applicant did not identify any TLAA-based exemptions. Based on the information provided by the applicant regarding the process used to identify these exemptions and its results, the staff finds, in accordance with 10 CFR 54.21(c)(2),
that there are no TLAA-based exemptions justified for continuation through the period of extended operation.4.1.3  ConclusionOn the basis of its review, the staff concludes that the applicant provided an acceptable list ofTLAAs, as required by 10 CFR 54.21(c)(1). The staff confirms, in accordance with 10 CFR 54.21(c)(2), that no exemption to the requirements of 10 CFR 50.12 had been granted based on a TLAA.
4-34.2  Reactor Vessel Neutron Embrittlement AnalysesReactor vessel integrity is governed by the requirements of 10 CFR Part 50, "DomesticLicensing of Production and Utilization Facilities." To comply with 10 CFR 50.60, all light-water reactors must meet the fracture toughness, pressure-temperature limits, and material surveillance program requirements of 10 CFR 50, Appendices G and H, for the reactor coolant pressure boundary (RCPB). The CLB analyses evaluating reduction of fracture toughness of the reactor vessel (RV) for 40-years are TLAAs. The RV neutron embrittlement TLAA has been projected to the end of the period of extended operation. Fifty-four effective full-power years (EFPYs) are projected for the end of the period of extended operation (60-years), assuming an average capacity factor of 90 percent for 60-years.During plant service, neutron irradiation reduces the fracture toughness of ferritic steel in thebeltline region of the RV for light-water nuclear power reactors. Areas of review to ensure that the RV and RV internals have adequate fracture toughness to prevent brittle failure during normal and off-normal operating conditions are: (1) RV fluence; (2) operating pressure-temperature (P-T) limits for heatup and cooldown operations, as well as hydrostatic and leak-testing conditions; (3) RV materials Charpy upper-shelf energy (C VUSE) reduction dueto neutron embrittlement; (4) adjusted reference temperature (ART) for RV materials because of neutron embrittlement; (5) RV circumferential weld examination relief; (6) RV axial weld failure probability; (7) reflood thermal shock of the RV internals; (8) BWRVIP-05, RV Axial Welds; and (9) BWRVIP-25, Core Plate. The adequacy of the analyses for these nine review areas is evaluated for the period of extended operation.The ART is defined as the sum of the initial (unirradiated) reference temperature (RT NDT), themean value of the adjustment in reference temperature caused by irradiation (delta RT NDT), anda margin term (m). Delta RT NDT is the product of a chemistry factor (CF) and a fluence factor(FF). The CF is dependent upon the amount of copper and nickel in the material and may be determined from tables in Regulatory Guide (RG) 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials," or from surveillance data. The FF is dependent upon the neutron fluence. The margin term is dependent upon whether the initial RT NDT is a plant-specific value ora generic value and whether the CF was determined using the tables in RG  1.99, Revision 2, or surveillance data. The margin term is used to account for uncertainties in the values of the initial
 
RT NDT, the copper and nickel contents, the fluence, and the calculation methods. RG  1.99,Revision 2, describes the methodology to be used in calculating the margin term. The mean
 
RT NDT is the sum of the initial RT NDT and the delta RT NDT, without the margin term. The mean RT NDT and ART calculations meet the requirements of 10 CFR 54.3(a). Therefore, they areconsidered TLAAs. The ART values for the RV materials are used for the P-T limits analysis.
The mean RT NDT values are used in the analysis of the circumferential weld examination reliefand the axial weld failure probability.Appendix G of 10 CFR Part 50, provides the requirements for maintaining acceptable levels ofupper-shelf energy (USE) for the RV beltline materials of operating reactors throughout the licensed lives of the facilities. 10 CFR 50, Appendix G, requires RV beltline materials to have a minimum USE value of 75 ft-lb in the unirradiated condition and to maintain a minimum USE value above 50 ft-lb throughout the life of the facility, unless it can be demonstrated through analysis that lower values of USE would provide acceptable margins of safety against fracture equivalent to those required by the American Society of Mechanical Engineers Boiler and 4-4Pressure Vessel ASME Code, Section XI, Appendix G. 10 CFR 50, Appendix G, also requiresthat the methods used to calculate USE values must account for the effects of neutron irradiation on the USE values for the materials and must incorporate any relevant RV surveillance capsule data that are reported through implementation of a plant's RV Material Surveillance Program, required by 10 CFR Part 50, Appendix H.RG  1.99, Revision 2, provides an expanded discussion regarding the calculation of USE valuesand describes two methods for determining USE values for RV beltline materials, depending onwhether or not a given RV beltline material is represented in the plant's RV material surveillance program (i.e., 10 CFR 50, Appendix H program). If surveillance data is not available, the USE value is determined in accordance with RG  1.99, Revision 2, Position 1.2. If surveillance data is available, the USE should be determined in accordance with RG  1.99, Revision 2, Position 2.2.
RG  1.99, Revision 2, Figure 2, describes how the percentage drop in USE is dependent upon the amount of copper in the material and the neutron fluence. Since the analyses performed in accordance with 10 CFR Part 50, Appendix G, are based on a flaw with a depth equal to one-quarter thickness (1/4T) of the RV wall, the neutron fluence used in the USE analysis is theneutron fluence at the 1/4T depth location.The applicant has described its evaluation of these TLAAs in LRA Section 4.2, "NeutronEmbrittlement of the Reactor Vessel and Internals," and LRA Section 4.7, "Other Plant-Specific TLAA." In order to demonstrate that neutron embrittlement does not significantly impact RV and RV internals integrity during the license renewal term, the applicant included a discussion of the following topics related to neutron embrittlement in LRA Sections 4.2 and 4.7:
RV neutron fluence (LRA Section 4.2.1)
Operating P-T Limits (LRA Section 4.2.2)
* RV materials Charpy USE reduction due to neutron embrittlement (LRA Section 4.2.3)
* ART for the reactor vessel materials due to neutron embrittlement (LRA Section 4.2.4)
* RV circumferential weld examination relief (LRA Section 4.2.5)
* RV axial weld failure probability (LRA Section 4.2.6)
* Reflood thermal shock of the RV internals (LRA Section 4.7.1)
* BWRVIP-05, RV axial welds, and
* BWRVIP-25, core plate4.2.1  Reactor Vessel Fluence4.2.1.1  Summary of Technical Information in the ApplicationLRA Section 4.2.1 summarizes the evaluation of RV fluence for the period of extendedoperation. General Electric (GE) Licensing Topical Report NEDC-32983P-A, approved by the staff for licensing applications, documents the method for the neutron flux calculation. The staff finds that this method generally adheres to the guidance in RG  1.190 for neutron flux evaluation. The calculated RV inner diameter (ID) fluence for 51.6 EFPY is 5.16 x 10 17 n/cm 2(E greater than 1 MeV). Extrapolated to 54 EFPY, the vessel surface ID fluence is 5.39 x 10 17n/cm 2 (E greater than 1 MeV). Using RG  1.99, Revision 2, Equation (3) results in a 54 EFPY 1/4T fluence of 3.98 x 10 17 n/cm 2 (E greater than 1 MeV). The 40-year beltline consists of fourplates (1-14, 1-15, 1-16, 1-17) and their connecting welds, all adjacent to the active fuel zone.
There are no nozzles in the beltline region. The beltline was re-evaluated for 60-years with the 4-5axial distribution of fast fluence at the reactor pressure vessel (RPV) wall. With the additionalfluence during the period of extended operation, the vertical section of the RV ID that will receive more than 1 x 10 17 n/cm 2 (E greater than 1 MeV) extends from 3.5 inches below the bottom to 10inches above the top of the active fuel. There are no nozzles in this region. The limiting plate and weld materials in the 40-year beltline remain the limiting materials for the period of extended operation.4.2.1.2  Staff EvaluationThe staff reviewed LRA Section 4.2.1 to verify, as required by 10 CFR 54.21(c)(1)(ii), that theanalyses have been projected to the end of the period of extended operation.The applicant has provided fluence values for the VYNPS RV beltline materials in LRASection 4.2.1. These fluence values were used throughout LRA Section 4.2 for the RV neutron embrittlement calculations. RG 1.190 provides guidance regarding acceptable methods for the benchmarking of vessel fluence methodologies based on the requirements of General Design Criterion (GDC) 31 and in part on GDCs 14 and 30. Therefore, the staff's review of the peak vessel fluence evaluation for VYNPS was based the on the adherence of the calculational method to the guidance provided in RG 1.190. In RAI 4.2-1, the staff requested additional information regarding the end-of-extended lifecalculated vessel fluence and its axial distribution. By letter dated September 20, 2006, the applicant responded that: VYNPS originally performed the fluence extrapolation using a 32 EFPY axialfluence profile provided in GE-NE-0000-2342-R1-NP dated July 2003. The results of this extrapolation were provided in response to RAI 3.1.1-17-P-01.A 60-year (51.6 EFPY) axial fluence profile is available inGE-NE-0000-0014-0292-01 dated May 2003. Both of these profiles were produced by GE as part of the extended power uprate and both are based on the expected plant operating history including the power uprate. The 60-year curve does show the peak fluence lower in the core (75 inches above the bottom of the active fuel (BAF) versus 85 inches), and consequently the 60-year curve has slightly higher fluence below the active fuel in the area of the recirculation inlet nozzles. VYNPS repeated the extrapolation to 54 EFPY for the 32 EFPY curve and extrapolated the 60 -year curve from 51.6 to 54 EFPY with the following
 
results.
4-61/4 T fluence, n/cm 2 (E>1 Mev)LocationOriginalExtrapolationfrom 32 EFPYcurveRevisedExtrapolationfrom 32 curveExtrapolationfrom 60-yearcurveBAF9.8E+169.8E+161.0E+17BAF + 19%1.2E+171.2E+171.2E+17nozzle6.7E+166.4E+167.5E+16nozzle + 19%7.9E+167.6E+169.0E+16As indicated in this table, the projected fluence at the nozzle is still less than1x10 17 n/cm 2 (E>1 Mev). Even when 19 percent is added to the extrapolatedvalue to account for possible error in the calculation as suggested by RAI 3.1.1-17-P-01, all values remain below 1x10 17 n/cm 2.The projected axial fluence profile was based on the projected operating plan,including the extended power uprate; therefore the projected operating plan supports the assumed power distribution to the end of the period of extended operation.The staff reviewed the applicant's response. The staff determined that the 60-year fluence valuewas calculated by General Electric using NRC approved methodology. For VYNPS, the end-of extended license irradiation in terms of EFPYs is estimated to be 51.6. The licensee conservatively extrapolated the results to 54 EFPYs. The results of the calculation are recorded in GE-NE-0000-0014-0292-01. The 60-year peak fluence appears at a lower elevation than the 40-year peak fluence. The peak fluence shift resulted from the extended power uprate. The calculation assumed the projected long term operation with the extended power uprate and expected fuel loadings factored into the evaluation. The staff finds the applicant's response acceptable since the proposed inside diameter peakfluence value of 5.16 x 10 17 n/cm 2 is at an elevation of 75 inches above the bottom active fuellevel. The value is considered to be conservative because of the extension of the operating time by 2.4 EFPYs. On this basis, the staff's concern described in RAI 4.2-1 is resolved.4.2.1.3  UFSAR SupplementThe applicant provided a UFSAR Supplement summary description of its TLAA evaluation of RVfluence in LRA Section A.2.2.1.1 which include the following:Calculated fluence is based on a time-limited assumption defined by the operatingterm. As such, fluence is the time-limited assumption for the TLAA that evaluates RV embrittlement.
4-7GE's Licensing Topical Report NEDC-32983P-A, which was approved by theNRC for licensing applications in Reference A.2-6, documents the method used for the neutron flux calculation. The staff finds that, in general, this method adheres to the guidance in RG  1.190 for neutron flux evaluation.The applicant's UFSAR Supplement summary description for the TLAA of the RV fluenceappropriately describes how the projected RV fluence is calculated for the extended period of operation for VYNPS.On the basis of its review of the UFSAR Supplement, the staff concludes that the summarydescription of the applicant's actions to address RV fluence is adequate.4.2.1.4  ConclusionOn the basis of its review, as discussed above, the staff concludes that the applicant hasdemonstrated, in compliance with 10 CFR 54.21(c)(1)(ii), that, for RV fluence, the analyses have been projected to the end of the period of extended operation. The staff also concludes that the UFSAR Supplement contains an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).4.2.2  Pressure-Temperature Limits 4.2.2.1  Summary of Technical Information in the ApplicationLRA Section 4.2.2 summarizes the evaluation of P-T limits for the period of extended operation.10 CFR Part 50, Appendix G, requires the RV to remain within established P-T limits calculated from materials and fluence data obtained through the Reactor Vessel Surveillance Program, during RV boltup, hydrotest, pressure tests, normal operation, and anticipated operational occurrences. In March 2003, the applicant requested a license amendment to change the P-T limits to incorporate data from analysis of the first surveillance capsule and to extend the curves to 32 EFPY. The staff approved this request as License Amendment 218. As stated in the safety evaluation, the applicant used conservative values of 1.24 x 10 18 n/cm 2 (E greater than 1 MeV)peak vessel fluence, 89 &deg;F 1/4T ART, and 73 &deg;F 3/4T ART to determine the P-T limits. LRATable 4.2-1 compares the bases for the present curves with the projected fluence and ARTs for 54 EFPY and shows that the projected values at 54 EFPY (fluence of 5.39 x 10 17 n/cm 2 , 1/4 TART of 68.5 &deg;F and a 3/4T ART of 56.9 &deg;F) are still less that those of the P-T curves. As such, theTLAA for P-T limits remains valid for the period of extended operation.
4-84.2.2.2  Staff EvaluationThe staff reviewed LRA Section 4.2.2 to verify in accordance with 10 CFR 54.21(c)(1)(i), that theanalyses remain valid for the period of extended operation.In its March 2003 license amendment request, VYNPS requested use of the present P-T limitcurves through 32 EFPY of facility operation. This request was approved by the NRC in a license amendment dated March 29, 2004. The applicant provided a comparison of the fluence and ART values for the 32 EFPY P-T limits with the projected 54 EFPY fluence and ART values for the extended period of operation, based on the 2002 fluence analysis in LRA Table 4.2-1. The staff finds that the new projected 54 EFPY fluence and ART values are, in fact, less than the 32 EFPY fluence and ART values, on which the current technical specification (TS) P-T limits are
 
based.In its request for additional information (RAI), the staff had a number of questions concerning theapplicant's TLAAs. For the P-T limits, it was unclear to the staff why the projected 54 EFPY fluence and ART values from LRA Table 4.2-1 are, in fact, less than the 32 EFPY fluence and ART values for the current TS P-T limits. Therefore, the staff requested, in RAI 4.2.2-1, that the applicant discuss the 1984 fluence analysis assumptions that resulted in conservative values for the 32 EFPY neutron fluence and ART values, taking into consideration why the 32 EFPY fluence and ART values are more conservative relative to the projected 54 EFPY fluence and ART values based on the 2002 fluence analysis.In its response to RAI 4.2.2-1, the applicant stated that the current 32 EFPY P-T limits wereoriginally prepared based on a 1/4T fluence of 1.24 x 10 18 n/cm 2 (E greater than 1 MeV) from the1984 fluence analysis. This fluence value was determined to be overly conservative based a subsequent 32 EFPY fluence calculation that generated a 1/4T fluence value of 2.2 x 10 17 n/cm 2(E greater than 1 MeV) from the 2002 fluence analysis. However, the applicant opted not to amend the existing 32 EFPY P-T limits to incorporate the 2002 32 EFPY fluence calculation, based on time and expense associated with the TS amendment. Therefore, the conservative existing P-T limits based on the 1984 32 EFPY fluence values were retained in the TSs. Given the conservatism inherent in the 1984 32 EFPY fluence and ART values, the applicant determined that the projected 54 EFPY fluence and ART values from the 2002 fluence analysis would remain bounded by the fluence and ART values for the 32 EFPY P-T limits currently established in the VYNPS TSs. The staff reviewed the applicant's response and finds the response acceptable since the projected 54 EFPY fluence and ART values from the 2002 fluence analysis would remain bounded by the fluence and ART values for the 32 EFPY P-T limits currently established in the VYNPS TSs. On this basis, the staff's concern described in RAI 4.2.2-1 is resolved.In RAI 4.2.2-2, the staff requested that the applicant discuss whether the 54 EFPY P-T limitcurve bases (fluence and ART values) from the 2002 fluence analysis summarized in LRA Table 4.2-1 take into consideration the VYNPS extended-power uprate (EPU) conditions. In its response to RAI 4.2.2-2, the applicant stated that the projected 54 EFPY fluence from the 2002 fluence analysis was calculated taking into consideration EPU conditions. Therefore, the 32 EFPY fluence and ART values from LRA Table 4.2-1 still bound the projected 54 EFPY fluence and ART values, including consideration of EPU conditions through the end of the period 4-9of extended operation. The staff reviewed the applicant's response and finds the responseacceptable since the 32 EFPY fluence and ART values still bound the projected 54 EFPY fluence and ART values, including consideration of EPU conditions through the end of the period of extended operation. On this basis, the staff's concern described in RAI 4.2.2-2 is resolved.The staff does not require the P-T limit curves for the extended period of operation to besubmitted as part of the applicant's LRA for this TLAA. However, the staff does require NRC approval of the P-T limit curves for the extended period of operation prior to the expiration of the facility's current P-T limit curves. LRA Section 4.2.2 of VYNPS states that the P-T limit curve bases for 54 EFPY are bounded by the bases for the current P-T limit curves, and, as such, the TLAA for the P-T limits remains valid in compliance with 10 CFR 54.21(c)(1)(i). Therefore, the staff requested, in RAI 4.2.2-3, that the applicant indicate when it intends to submit P-T limit curves for NRC approval for the extended licensed period of operation (54 EFPY).In its response to RAI 4.2.2-3, the applicant stated that it plans to submit a TS amendmentrequesting extension of the P-T limit curves prior to the expiration of the P-T limit curves currently established in the VYNPS TSs. The staff reviewed the applicant's response and finds the response acceptable since the applicant indicated that it plans to submit a P-T limit curves for NRC approval for the extended licensed period of operation. On this basis, the staff's concern described in RAI 4.2.2-3 is resolved.The staff finds that the applicant's plan to manage the P-T limits is acceptable because changesto the P-T limit curves will be implemented by the license amendment process (i.e., through revisions of the plant TS) and will meet the requirements of 10 CFR 50.60 and 10 CFR 50, Appendix G.4.2.2.3  UFSAR SupplementThe applicant provided a UFSAR Supplement summary description of its TLAA evaluation of P-Tlimits in LRA Section A.2.2.1.2. which include the following:In March 2003, VYNPS submitted a license amendment request(Reference A.2-4) to change the P-T limits to incorporate data from analysis of the first VYNPS surveillance capsule and to extend the curves to 32 EFPY. The NRC approved this submittal as Amendment 218 to the VYNPS license (Reference A.2-5). As stated in the SER (Reference A.2-5), VYNPS used conservative values for determining the 32 EFPY P-T limits. The projected fluence and ARTs for 54 EFPY, including the EPU, are still less than the conservative values on which the 32 EFPY P-T curves are based. As such the current 32 EFPY P-T limits do not require modification for the period of extended operation and the TLAA remains valid in compliance with 10 CFR 54.21(c)(1)(i).The staff finds applicant's UFSAR Supplement summary description of the TLAA for the P-Tlimits appropriately describes how the applicant will determine the P-T limits for the extended period of operation for VYNPS. On the basis of its review of the UFSAR Supplement, the staff concludes that the summarydescription of the applicant's actions to address P-T limits is adequate.
4-104.2.2.4  ConclusionThe staff reviewed the applicant's TLAA for the P-T limits, as summarized in LRA Section 4.2.2,including the RAI response, dated November 9, 2006, and finds that the applicant plans to submit an application to amend the P-T limits for the period of extended operation for VYNPS in accordance with the applicable regulatory requirements. The staff therefore concludes that the applicant's TLAA for the VYNPS P-T limits will be in compliance with the staff's acceptance criterion for TLAAs as required by CFR 54.21(c)(1)(ii), when the amendment application to revise the P-T limits for the period of extended operation is submitted and the staff-approved P-T limits are incorporated into the VYNPS TS. Safety margins established and maintained during the current operating term will be maintained during the period of extended operation as required by 10 CFR 54.21(c)(1). On the basis of its review, as discussed above, the staff concludes that the applicant hasdemonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that, for P-T limits, the analyses remain valid for the period of extended operation. The staff also concludes that the UFSAR Supplement contains an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).4.2.3  Charpy Upper-Shelf Energy 4.2.3.1  Summary of Technical Information in the ApplicationLRA Section 4.2.3 summarizes the evaluation of C VUSE for the period of extended operation.10 CFR 50, Appendix G, requires that RV beltline materials "have Charpy upper-shelf energy -
of no less than 75 ft-lb initially and must... maintain Charpy upper-shelf energy throughout thelife of the vessel of no less than 50 ft-lb."RG 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials," provides twomethods or positions for estimating C VUSE at end of life. Position 1 applies to material withoutsurveillance data and Position 2, to material with surveillance data. Position 2 requires a minimum of two sets of credible material surveillance data. As the applicant has data from only one material surveillance capsule, Position 2 does not apply. For Position 1, the percentage drop in C VUSE for a stated copper content and neutron fluence is determined by reference toRG 1.99, Revision 2, Figure 2. This percentage drop is applied to the initial C VUSE to obtain the adjusted C VUSE. LRATable 4.2-2 calculates the end of life C VUSE by this method. Safety Analysis ReportNEDC-33090P documents the most recent calculations of C VUSE. Analyses were done for51.6 EFPY. Results of NEDC-33090P were extrapolated to 54 EFPY. The unirradiated surveillance specimens were from plate 1-14 with a C VUSE of 89 ft-lb (137 ft-lb times 0.65). The 54 EFPY C VUSE value for plate 1-14 was calculated in accordance with RG 1.99, Position 1,Figure 2. Specifically, the calculation used the formulae for the lines to calculate the percentage drop in C VUSE with the fluence determined in SER Section 4.2.1. For 54 EFPY, LRA Table 4.2-2shows the minimum projected C VUSE for plate 1-14 remaining above the 50 ft-lb requirement of10 CFR Part 50, Appendix G.
4-11Initial (un-irradiated) USE data for the weld materials and for plates 1-15, 1-16, and 1-17 do notexist. The BWR Owners Group prepared an equivalent margins analysis (EMA) for plants without this data in topical report BWRVIP-74, "BWR Vessel and Internals Project, BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines (BWRVIP-74)." The NRC reviewed and accepted the evaluation, as documented in the staff's SER on BWRVIP-74, dated July 27, 2001. Calculation of plant-specific end of life (EOL) USE is impossible without initial USE data for RV beltline materials. Therefore, based upon BWRVIP-74, a plant without initial USE data may calculate the percent drop in USE and show that the percent drop is less than the percent drop from the EMA. BWRVIP-74 gives allowable percent drops in USE of 23.5 percent for BWR 3-6 plates and 39 percent for welds. LRA Table 4.2-3 uses the BWRVIP-74 method to verify that the reductions in USE for limiting RV beltline plate and weld materials at VYNPS remain less than the reduction calculated in the BWRVIP-74 EMA. The EMA for the non-limiting plates and welds are shown in LRA Table 4.2-2, along with the EOL USE data for RV beltline plate 1-14. For RV beltline plate 1-14, the applicant was able to directly demonstrate that the actual calculated EOL USE value remained above the 50 ft-lb acceptance requirement of 10 CFR 50, Appendix G. Therefore, the use of the EMA from the BWRVIP-74 report was not required. As such, this TLAA has been projected to the end of the period of extended operation as required by 10 CFR 54.21(c)(1)(ii).4.2.3.2  Staff EvaluationThe staff reviewed LRA Section 4.2.3 to verify in accordance with 10 CFR 54.21(c)(1)(ii), that theanalyses have been projected to the end of the period of extended operation.Section IV.A.1.a of 10 CFR Part 50, Appendix G to, requires in part that RV beltline materialshave C VUSE values in the transverse direction for base metal and along the weld for weldmaterial of no less than 50 ft-lb, unless it is demonstrated in a manner approved by the staff, that lower values of C VUSE will ensure margins of safety against fracture equivalent to thoserequired by ASME Code, Section XI, Appendix G.In accordance with RG 1.99, Revision 2, the predicted decrease in USE due to neutronembrittlement during plant operation is dependent upon the amount of copper in the material and the predicted neutron fluence for the material. RG 1.99, Revision 2, Position 1.2, specifies methods for calculating the predicted decrease in USE for materials that do not have sufficient credible surveillance data available. The staff finds that the applicant correctly used Position 1.2 for calculating the predicted percentage decrease in USE for the extended period of operation, because only one credible set of surveillance data is available for the VYNPS RV.Initial USE values were unavailable for RV beltline plates 1-15, 1-16, 1-17, and all welds atVYNPS. As such, the applicant utilized the results of the EMA that were summarized in BWRVIP-74, Appendix B. The EMA from BWRVIP-74 utilized the technique originally developed in GE Topical Report NEDO-33205-A, "10 CFR Part 50, Appendix G, Equivalent Margin Analysis for Low Upper-Shelf Energy in BWR/2 through BWR/6 Vessels," Revision 1, February 1994. The staff finds that the applicant correctly applied the acceptance criteria from BWRVIP-74 for the allowable percentage drop in the USE by demonstrating the predicted percentage decrease in the USE at 54 EFPY, as determined from RG 1.99, Revision 2, Position 1, was less than the EMA acceptance criteria for these plates and welds.
4-12The applicant was able to directly calculate the predicted EOL USE value for RV beltline plate1-14 at VYNPS because initial (unirradiated) values for USE were available for this particular plate. The staff confirmed that the initial USE values were appropriately based on credible surveillance data that were representative of plate 1-14. The applicant appropriately determined the predicted EOL USE values for the extended period of operation by applying the predicted percentage decrease in USE from RG 1.99, Revision 2, to the initial USE values.The applicant submitted plant-specific information in LRA Tables 4.2-2 and 4.2-3 to demonstratethat the applicable beltline materials for the VYNPS RV meet the applicable EMA acceptance criteria from the BWRVIP-74 report and, in the case of plate 1-14, the predicted EOL USE meets the requirements of 10 CFR 50, Appendix G, at the end of the period of extended operation. The projected USE data at the end of the period of extended operation for the limiting beltline plate and weld materials are summarized in the table below.VY RV MaterialRG  1.99, Revision 2Predicted USE % Drop Or EOL USE ValueEOL USE Acceptance CriterionEvaluation Result Limiting Plate 1-15 110.7%% USE drop must be
< 23.5%Acceptable per10 CFR 54.21(c)(1)(ii)Limiting Welds 1-338A, B, C 111.19%% USE drop must be
< 39%Acceptable per 10 CFR 54.21(c)(1)(ii)
Plate 1-14 267.7 ft-lb.USE must be
> 50 ft-lbAcceptable per 10 CFR 54.21(c)(1)(ii) 1 As noted in text, acceptance criteria established per BWRVIP-74 2 As noted in text, acceptance criteria established per 10 CFR 50, Appendix G.The staff verified the values for the percent decrease in USE resulting from neutron irradiationusing the methodology in RG  1.99, Revision 2 and finds that all the beltline materials meet the applicable acceptance criteria.4.2.3.3  UFSAR SupplementThe applicant provided a UFSAR Supplement summary description of its TLAA evaluation of C VUSE in LRA Section A.2.2.1.3. which included the following:The predictions for percent drop in USE at 54 EFPY are based on chemistry dataand unirradiated USE data submitted to the NRC in support of the VYNPS power uprate, and the 1/4T fluence maximum value.The 54 EFPY USE values were calculated using RG 1.99, Position 1, Figure 2;specifically, the formula for the lines was used to calculate the percent drop in
 
USE.
4-13Because VYNPS does not have complete unirradiated data for all beltlinematerials, equivalent margin analyses were done for the limiting plate and weld, using the technique in NEDO-32205. The results showed that the percent reductions in USE are less than the limiting decreases identified in the NRC SER for BWRVIP-74. A conservative assumption used in the calculation of USE reduction is that no credit is taken for axial or azimuthal lead factors to reduce the peak fluence. Instead, the maximum calculated 1/4T fluence value is assumed forall plates and welds.The applicant's UFSAR Supplement summary description is consistent with the staff analysis forthe TLAA of the USE in SER Section 4.2.3.2. The UFSAR Supplement summary description summarizes the applicable USE requirements that must be met to ensure continued compliance with 10 CFR 50, Appendix G, during the period of extended operation. The staff therefore finds that UFSAR Supplement summary description for the TLAA of the USE is acceptable.On the basis of its review of the UFSAR Supplement, the staff concludes that the summarydescription of the applicant's actions to address C VUSE is adequate.4.2.3.4  ConclusionOn the basis of its review, as discussed above, the staff concludes that the applicant hasdemonstrated, in accordance with 10 CFR 54.21(c)(1)(ii), that, for C VUSE, the analyses havebeen projected to the end of the period of extended operation. The staff also concludes that the UFSAR Supplement contains an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).4.2.4  Adjusted Reference Temperature 4.2.4.1  Summary of Technical Information in the ApplicationLRA Section 4.2.4 summarizes the evaluation of ART for the period of extended operation.Irradiation by high-energy neutrons raises the value of RT NDT for the RV. RT NDT is the referencetemperature for nil-ductility transition as defined in ASME Code, Section NB-2320. The initial
 
RT NDT is determined through testing un-irradiated material specimens. The shift in referencetemperature, RT NDT, is the difference in the 30 ft-lb index temperatures from the averageCharpy curves measured before and after irradiation. The ART = RT NDT + RT NDT + margin. The applicant's response to General Letter (GL) 92-01 included chemistry data; interpolatedchemistry factors (CFs) from RG 1.99, Table 1; initial RT NDT values and standard deviations fromNEDC-33090P, Table 3-2a, "Safety Analysis Report;" and calculated margins as twice the square root of the sum of the squares of the two standard deviations. ARTs were for 1/4 Tfluence. FFs were calculated using RG 1.99, Revision 2, Equation 2.
4-14The applicant calculated extrapolated RT NDT values by multiplying the CF and the FF for eachplate and weld, then added the initial RT NDT, the calculated RT NDT, and the calculated marginsfor the new ART value. LRA Table 4.2-4 shows the 54 EFPY values of ART. As shown in the table, the plates remain the limiting subcomponents rather than the welds, and plate 1-14 remains the limiting plate. All calculated values are well below the 200 F suggested in RG  1.99,Section 3, and are acceptable for the period of extended operation. The TLAA for RT NDT is thusprojected through the period of extended operation.4.2.4.2  Staff EvaluationThe staff reviewed LRA Section 4.2.4 to verify in accordance with 10 CFR 54.21(c)(1)(ii), that theanalyses have been projected to the end of the period of extended operation.The applicant calculated the 54 EFPY fluences for the VYNPS RV beltline materials using thefluence methodology of GE's Licensing Topical Report NEDC-32983P-A. Since this methodology is approved by the NRC, the calculated fluences provided in the LRA are acceptable. The fluence values for the VYNPS RV beltline materials at 54 EFPY, given in LRA Table 4.2-4, correspond to the fluence values provided in LRA Section 4.2.1. In reviewing the initial RT NDT data, chemistry data (percent Cu and percentNi), and CF values forthe RV beltline materials provided by the applicant in LRA Table 4.2-4, the staff found that initial
 
RT NDT values were provided that are less conservative than the corresponding initial RT NDTvalues that were established in the staff's Reactor Vessel Integrity Database (RVID) for the VYNPS RV beltline materials. Based on the non-conservatism with respect to the initial RT NDTvalues established in the RVID, the staff requested, in RAI 4.2.4-1, that the applicant provide additional information that points to where the NRC staff authorized the use of the specific initial
 
RT NDT values listed in LRA Table 4.2-4 for determining the ART values. In its November 9, 2006 response to RAI 4.2.4-1, the applicant stated that the initial RT NDTvalues listed in LRA Table 4.2-4 were originally provided to the NRC with the proposed TSamendment submitted on September 10, 2003, in support of the EPU. The NRC SER authorizing the EPU was issued on March 2, 2006. The justification for the use the initial RT NDTvalues listed in LRA Table 4.2-4 was provided in Report NEDC-33090P, "Updated Evaluation of Reactor Pressure Vessel Material Properties for Vermont Yankee Nuclear Power Station," which was included as part of September 2003 submittal for the proposed EPU TS amendment. This technical report was previously evaluated by the staff as part of the review for the EPU. In the course of performing the review for the EPU, the NRC performed confirmatory calculations of the 32 EFPY ART values under EPU conditions and concluded that the ART values were acceptable, based, in part, on the new initial RT NDT values. The staff finds that this responseresolves the issue in RAI 4.2.4-1.The staff independently reviewed all ART calculations in LRA Table 4.2-4 based on theapproved chemistry and fluence data and finds that the applicant appropriately followed the guidance of RG 1.99, Revision 2, in determining the projected 54 EFPY ART values for the VYNPS RV beltline materials.
4-154.2.4.3  UFSAR SupplementThe applicant provided a UFSAR Supplement summary description of its TLAA evaluation ofadjusted reference temperature in LRA Section A.2.2.1.4. which include the following:VYNPS has projected values for ART at 54 EFPY using the methodology ofRG  1.99. These values were calculated using the chemistry data, margin values, initial RT NDT values, and chemistry factors (CFs) submitted to the NRC in supportof the VYNPS power uprate, and the 1/4T fluence maximum value. New fluencefactors (FFs) were calculated using the expression in RG 1.99, Revision 2, Equation 2 using 54 EFPY fluence values.The RT NDT TLAA has been projected through the period of extended operation,with acceptable results, in compliance with 10 CFR 54.21(c)(1)(ii).The staff finds that the applicant used the staff-approved methods of RG 1.99, Revision 2, forcalculating projected 54 EFPY ART values for the VYNPS RV beltline materials. The applicant's UFSAR Supplement summary description is consistent with the staff analysis for the TLAA of the ART in SER Section 4.2.4.2. On the basis of its review of the UFSAR Supplement, the staff concludes that the summarydescription of the applicant's actions to address adjusted reference temperature is adequate.4.2.4.4  ConclusionThe staff reviewed the applicant's TLAA of the ART calculations, as summarized in SERSection 4.2.4, including the RAI response dated November 9, 2006, and finds that the applicant's calculations of the ART values for the RV beltline materials, as projected through the period of extended operation for VYNPS, are in conformance with the recommended guidelines of RG 1.99, Revision 2. On the basis of its review, as discussed above, the staff concludes that the applicant hasdemonstrated, in accordance with 10 CFR 54.21(c)(1)(ii), that, for adjusted reference temperature, the analyses have been projected to the end of the period of extended operation.
The staff also concludes that the UFSAR Supplement contains an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).4.2.5  Reactor Vessel Circumferential Welds Inspection Relief 4.2.5.1  Summary of Technical Information in the ApplicationLRA Section 4.2.5 summarizes the evaluation of RV circumferential welds inspection relief forthe period of extended operation. BWRVIP-74 reiterated the recommendation of BWRVIP-05 to exempt RPV circumferential welds from examination. The NRC SER for BWRVIP-74 agrees but requires plants to request this relief individually by demonstrating that at the expiration of the current license the circumferential welds will satisfy the BWRVIP-05 limiting conditional failure probability for circumferential welds. The applicant requested relief but has evaluated the welds only to the end of the current period of operation. The changes in metallurgical conditions expected over the period of extended operation require additional analysis for 54 EFPY for the 4-16RV circumferential weld inspection relief request. The evaluations have been projected to 54EFPY. The applicant's relief request includes an analysis showing that the RV parameters after 32 EFPY were within the bounding Chicago Bridge & Iron (CBI) 32 EFPY vessel parameters so for the circumferential welds, there is a conditional probability of failure lower than that stated in the safety evaluation of BWRVIP-05.The staff's evaluation of BWRVIP-05 utilized the FAVOR code to perform a probabilisticfracture mechanics analysis to estimate the RV shell weld failure probabilities. Three key assumptions of the probabilistic fracture mechanics analysis were: 1) the neutron fluence was the estimated EOL mean fluence; 2) the chemistry values were mean values based on vessel types; and 3) the potential for beyond-design-basis events was considered. LRA Table 4.2-5 provides a comparison of the VYNPS RV limiting circumferential weld parameters to those used in the NRC evaluation of BWRVIP-05 for the first two key assumptions. Data provided in LRA Table 4.2-5 was supplied from BWRVIP-05, Table 4.4 and BWRVIP-05, "Final Safety Evaluation Report," Table 2.6-5.The VYNPS 54 EFPY fluence is substantially lower than the limits of the NRC analysis. As aresult, the shift in reference temperature, delta RT NDT, is lower for VYNPS at 54 EFPY comparedto the NRC analysis. This lower delta RT NDT value yields a mean RT NDT value that is considerablylower than the NRC mean analysis value. Therefore, the RV circumferential shell weld embrittlement due to neutron irradiation has a negligible effect on the probabilities of RV circumferential shell weld failure. The mean RT NDT value at 54 EFPY is bounded by the 64 EFPYmean RT NDT provided by the NRC. Based on this analysis, the applicant concluded that the VYNPS RV circumferential weldconditional failure probability is bounded by the staff analysis of BWRVIP-05. The RPV circumferential weld parameters at 54 EFPY will remain within the staff's (64 EFPY) bounding CBI vessel parameters. Thus, the conditional probability of failure for the circumferential welds remains below that stated in the staff's safety evaluation of BWRVIP-05. This analysis has been projected for the period of extended operation.4.2.5.2  Staff EvaluationThe staff reviewed LRA Section 4.2.5 to verify, in accordance with 10 CFR 54.21(c)(1)(ii), that theanalyses have been projected to the end of the period of extended operation.The technical basis for relief from the ASME Code, Section XI, "Circumferential Weld InserviceInspection (ISI) Requirements," is discussed in the staff's final SER concerning the BWRVIP-05 report, which is enclosed in a July 28, 1998, letter from Mr. G.C. Lanais, NRC, to Mr. C. Terry, the BWRVIP Chairman. In this letter, the staff concludes that since the failure frequency for circumferential welds in BWR plants is significantly below the criterion specified in RG 1.154, "Format and Content of Plant-Specific Pressurized Thermal Shock Safety Analysis Reports for Pressurized Water Reactors," and below the core damage frequency of any BWR plant, the continued inspection would result in a negligible decrease in an already acceptably low RV failure probability. Therefore, elimination of the ISI requirements for RV circumferential welds is justified.
The staff's letter indicated that BWR applicants may request relief from the ISI requirements of 10 CFR 50.55a(g) for volumetric examination of circumferential RV welds by demonstrating that:
(1) at the expiration of the license, the circumferential welds satisfy the limiting conditional failure probability for circumferential welds in the NRC staff's July 28, 1998 evaluation, and (2) the 4-17applicant implemented operator training and established procedures that limit the frequency ofcold over-pressure events to the frequency specified in the staff's SER. The letter indicated that as part of any BWR LRA, the requirements for inspection of RV circumferential welds during an additional 20-year period of extended operation must be reassessed, on a plant-specific basis. In addition, the applicant must request relief from the ISI requirements for volumetric examination of circumferential welds for the extended license term in accordance with the requirements of 10 CFR 50.55a(g).Section A.4.5 of the BWRVIP-74 report indicates that the staff's SER of the BWRVIP-05 reportconservatively evaluated the BWR RVs to 64 EFPY, which is 10 EFPY greater than what is realistically expected for the end of the period of extended operation. The NRC staff used the mean RT NDT value to evaluate the failure probability of BWR circumferential welds at 32 and 64EFPY in the staff SER on the BWRVIP-05 report, dated July 28, 1998. The neutron fluence used in this evaluation was the neutron fluence at the RV inner diameter clad-weld interface.Since the staff analysis discussed in the BWRVIP-74 report is a generic analysis, the applicantsubmitted plant-specific information to demonstrate that the VYNPS beltline materials meet the criteria specified in the report. To demonstrate that the VYNPS RV has not become embrittled beyond the basis for the relief, the applicant, in LRA Table 4.2-5, supplied a comparison of 54 EFPY material data for the limiting VYNPS circumferential weld with that of the 64 EFPY reference case in Appendix E of the staff's SER of the BWRVIP-05 report. The VYNPS material data included amounts of copper and nickel, chemistry factor, the neutron fluence, delta RT NDT ,initial RT NDT, and mean RT NDT for the limiting circumferential weld at the end of the period ofextended operation. The staff verified the validity of the data for the copper and nickel contents and the initial RT NDT values for the VYNPS RV beltline materials based on the evaluation in SERSection 4.2.4. The 54 EFPY mean RT NDT value for the limiting beltline circumferential weld atVYNPS is 32.9 F. The staff checked the applicant's calculations using the data presented inLRA Table 4.2-5 and found them accurate. This 54 EFPY mean RT NDT value for the limitingVYNPS circumferential weld is bounded by the 64 EFPY mean RT NDT value of 70.6 F used bythe NRC for determining the conditional failure probability of a circumferential weld. The 64 EFPY mean RT NDT value from the staff SER dated July 28, 1998, is representative of a Chicago Bridge& Iron (CBI) weld because CBI fabricated the circumferential welds in the VYNPS RV. Since the VYNPS 54 EFPY mean RT NDT value is less than the 64 EFPY value from the staff SER datedJuly 28, 1998, the staff concludes that the VYNPS RV conditional failure probability is bounded by the NRC analysis.Based on the above, the staff finds that the applicant adequately addressed condition (1) fromBWRVIP-74, Section A.4.5 by demonstrating that the VYNPS RV circumferential welds will satisfy the limiting conditional failure probability for circumferential welds established in the staff's SER on BWRVIP-05 at the end of the period of extended operation. However, the applicant did not address condition (2) from BWRVIP-74, Section A.4.5, which specifies that applicants must demonstrate that they have implemented operator training and established procedures that limit the frequency of cold over-pressure events to the frequency specified in the staff's SER. In RAI 4.2.5-1, the staff requested that the applicant address condition (2) as it relates to the proposed period of extended operation.
4-18In its response to RAI 4.2.5-1, the applicant provided a description of reactor operator trainingand related procedural controls designed to limit the frequency of cold over-pressure events. This description was included in the original request for relief from RV circumferential weld examination requirements for the current licensed operating term. As part of its response to RAI 4.2.5-1, the applicant stated that this training remains in effect and will continue throughout the period of extended operation. Based on its review, the staff finds that the applicant's response to RAI 4.2.5-1 is acceptable because the applicant adequately addressed condition (2) from BWRVIP-74, pertaining to the implementation of operator training and procedures for limiting the frequency of cold over-pressure events that will remain in effect during the period of extended operation. The staff's concern described in RAI 4.2.5-1 is resolved.In accordance with 10 CFR 50.55a(g), the staff requires that a request for relief from the ASMECode, Section XI, "Circumferential Shell Weld Examination Requirements" be submitted for the extended period of operation. In RAI 4.2.5-2, the staff requested that the applicant indicate when it would apply for relief from the ASME Code, Section XI "Circumferential Shell Weld Examination Requirements" for the extended licensed period of operation.In its response to RAI 4.2.5-2, the applicant stated that it will submit the necessary relief requestfor each ISI interval within 12 months after the completion of the previous ISI interval, as required by 10 CFR 50.55a(g). The staff finds the applicant's response to RAI 4.2.5-2 acceptable. The staff's concern described in RAI 4.2.5-2 is resolved.In the July 28, 1998 SER on BWRVIP-05, the staff concludes that examination of the RVcircumferential shell welds must be performed if the corresponding volumetric examinations of the RV axial shell welds revealed the presence of an age-related degradation mechanism. In RAI 4.2.5-3, the staff requested that the applicant confirm whether or not previous volumetric examinations of the RV axial shell welds have shown any indication of cracking or other age-related degradation mechanisms in the welds.In its response to RAI 4.2.5-3, the applicant stated that previous examinations of the RV axialshell welds at VYNPS have not identified any relevant indications of cracking or other age-related degradation mechanisms in the welds. The staff finds the applicant's response to RAI 4.2.5-3 acceptable. The staff's concern described in RAI 4.2.5-3 is resolved.The staff finds that the applicant's evaluation for this TLAA is acceptable because the VYNPS 54EFPY conditional failure probability for the RV circumferential welds is bounded by the NRC analysis in the staff SER dated July 28, 1998, and the applicant will be using procedures and training to limit cold over-pressure events during the period of extended operation. This analysis satisfies the evaluation requirements of the staff SER dated July 28,1998. However, the applicant is still required to request relief for the circumferential weld examination for the extended period of operation as required by 10 CFR 50.55a(g).
4-194.2.5.3  UFSAR SupplementThe applicant provided a UFSAR Supplement summary description of its TLAA evaluation of RVcircumferential welds inspection relief in LRA Section A.2.2.1.5., which includes:Relief from RV circumferential weld examination requirements of GL 98-05 is based onassessments indicating an acceptable probability of failure per reactor operating year. The analysis is based on RV metallurgical conditions as well as flaw indication sizes and frequencies of occurrence that are expected at the end of a licensed operating period.VYNPS requested NRC approval for this relief for the remainder of the original40-year license term. The basis for this request is an analysis that satisfied the limiting conditional failure probability for the circumferential welds at the expiration of the current license, based on the NRC SERs for BWRVIP-05 and BWRVIP-74 and the extent of neutron embrittlement.The 54 EFPY fluence value for VYNPS is considerably lower than thecorresponding 64 EFPY generic value. As a result, the shift in reference temperature is lower than the 64 EFPY shift in the NRC analysis. However, the unirradiated reference temperature of the VYNPS material is higher than the initial value assumed in the NRC analysis. This combination of opposing effects yields an adjusted reference temperature that is lower than the NRC mean analysis value. Therefore, this TLAA has been projected to the end of the period of extended operation as required by 10 CFR 54.21(c)(1)(ii).The applicant's UFSAR Supplement summary description for the TLAA of the RV circumferentialweld examination relief appropriately discusses how the conditional failure probability for the RV circumferential welds is bounded by the NRC analysis in the staff SER dated July 28, 1998. The applicant's UFSAR Supplement summary description is consistent with the staff analysis for the TLAA of the RV circumferential weld examination relief in SER Section 4.2.5.2. On the basis of its review of the UFSAR Supplement, the staff concludes that the summarydescription of the applicant's actions to address RV circumferential welds inspection relief is adequate.4.2.5.4  ConclusionThe staff reviewed the applicant's TLAA of the RV circumferential weld examination relief, assummarized in LRA Section 4.2.5, including the RAI response dated November 9, 2006. The staff finds that the applicant appropriately describes how the conditional failure probability for the RV circumferential welds is bounded by the NRC analysis in the staff SER on the BWRVIP-05 report, dated July 28, 1998, and how the applicant's procedures and training will be used to limit cold over-pressure events during the period of extended operation for VYNPS. On the basis of its review, as discussed above, the staff concludes that the applicant hasdemonstrated, as required by 10 CFR 54.21(c)(1)(ii), that, for RV circumferential welds inspection relief, the analyses have been projected to the end of the period of extended operation. The staff also concludes that the UFSAR Supplement contains an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).
4-204.2.6  Reactor Vessel Axia l Weld Failure Probability4.2.6.1  Summary of Technical Information in the ApplicationLRA Section 4.2.6 summarizes the evaluation of RV axial weld failure probability for the period ofextended operation. Applicants must show that the failure frequency of axially-oriented RPV welds remains below the 5 x 10
-6 calculated in the BWRVIP-74 SER. This finding is documentedin the March 7, 2000 BWRVIP-05 supplement to the final SER. The supplement, provided by the BWRVIP, contains the NRC staff evaluation of information regarding axial weld failure rates due to low temperature over-pressure events, using specific staff recommendations on input variables. The axial weld failure probability meets the requirements of 10 CFR 54.3(a). As such, it is a TLAA. The applicant discussed the assumptions associated with the supplement to the NRC SER forBWRVIP-05, which concluded that the axial weld failure rate in the BWR fleet at the end of 40-years is no more than 5 x 10
-6 per reactor year. This generic BWR axial weld failure rate isdependent upon given assumptions on flaw density, distribution, and location. The failure rate also assumes that "essentially 100 percent" of the RV axial welds will be inspected.The applicant compared the limiting axial weld properties at 54 EFPY for VYNPS with the limitingaxial weld properties provided in the supplement to the NRC SER for BWRVIP-05. The supplemental SER stated that the axial welds for the Clinton plant are the limiting welds for the BWR fleet, and the vessel failure probability determined for Clinton should bound the BWR fleet.
The VYNPS limiting axial weld 54 EFPY mean RT NDT value is within the limits of the mean RT NDTvalue for Clinton. Analysis performed by the NRC staff in the BWRVIP-05 SER supplement resulted in an NRC-calculated axial weld failure probability of 2.73 x 10
-6 per reactor year. TheVYNPS limiting axial weld mean RT NDT value also falls well within the 64 EFPY value reported inBWRVIP-05 and the 64 EFPY value reported in Table 2.6-5 of the staff's original SER on BWRVIP-05. Based on the above comparisons, as summarized in LRA Table 4.2-4, the applicant concluded that the probability of failure for the RV axial welds is bounded by the NRC evaluation.
Therefore, this analysis has been projected for the period of extended operation.4.2.6.2  Staff EvaluationThe staff reviewed LRA Section 4.2.6 to verify in accordance with 10 CFR 54.21(c)(1)(ii), that theanalyses have been projected to the end of the period of extended operation.In its July 28, 1998 letter to Mr. C. Terry, the BWRVIP Chairman, the staff identified a concernregarding the failure frequency of axial welds in BWR RVs. In response to this concern, the BWRVIP supplied evaluations of axial weld failure frequency in letters dated December 15,1998, and November 12, 1999. The staff's BWRVIP-05 supplemental SER on these analyses is enclosed in a March 7, 2000 letter from Mr. J. Strosnider (NRC) to Mr. C. Terry (BWRVIP). The staff performed a generic analysis using Clinton as a model for BWR RVs manufactured by CBI and which demonstrated that a mean axial weld RT NDT of 91F resulted in a RV failure frequencyof 2.73 x 10
-6 per reactor-year of operation. The applicant calculated, and the staff confirmed, thatthe limiting axial weld mean RT NDT value for VYNPS at 54 EFPY is 16.5F, This RT NDT valuesupports the conclusion that the failure frequency for the VYNPS RV axial welds will be far less than 5 x 10
-6 per reactor-year of operation at the end of the period of extended operation.Therefore, this analysis is acceptable.
4-21The limiting axial weld failure probability calculated by the NRC staff in the BWRVIP-05 SERsupplement is based on the assumption that "essentially 100 percent" (i.e., greater than 90 percent) examination coverage of all RV axial welds can be achieved in accordance with ASME Code, Section XI requirements. In RAI 4.2.6-1, the staff requested that the applicant indicate whether ISI examinations achieve "essentially 100 percent" (i.e., greater than 90 percent) overall examination coverage for the RV axial welds for the duration of the current licensed operating period. If less than 90 percent overall examination coverage is achieved for the RV axial welds, the staff requested that the applicant revise their TLAA of the RV axial welds to account for the effects of the limited scope examination coverage.In its response to RAI 4.2.6-1, the applicant stated that, because of various obstructions withinthe RV, VYNPS had not been able to inspect "essentially 100 percent" of the RV beltline axial welds. VYNPS was granted an ISI Program relief by the NRC for the third ISI interval authorizing limited scope examination coverage for specified RV axial welds. The limited-scope examinations resulted in an overall coverage of 65 percent of the total axial weld length in the beltline region.
The technical basis for granting this relief from the ASME Code, Section XI requirements mandating "essentially 100 percent" examination coverage of all axial welds for the third ISI interval is documented in a February 18, 1999 staff SER.Examinations of the axial welds during Refueling Outage 24 (in the facility's fourth ISI interval)resulted in significantly greater coverage for all but two welds that could not be examined. Axial welds F1 and F2 were obstructed from any volumetric examination coverage during the 2004 inspection because of the installation of shroud repair tie rods prior to the 2004 inspection.
However, axial welds F1 and F2 each received an overall partial volumetric coverage of 65 percent of their respective weld volume during the third ISI interval. The remaining axial welds (not including welds F1 and F2) received an average overall volumetric coverage of 88 percent.
The applicant stated that the request for relief from full examination coverage of the RV axial welds will be submitted prior to the end of the fourth ISI interval, as required by 10 CFR 50.55a.There is a large margin between the limiting axial weld mean RT NDT value of 16.5F for VYNPS at54 EFPY and the analysis performed by the NRC staff in the BWRVIP-05 SER supplement which yielded a mean RT NDT value of 91F for the Clinton plant. Therefore, the difference between theaxial weld coverage achieved for the fourth ISI interval at VYNPS and the 90 percent minimum coverage required to meet the "essentially 100 percent" examination coverage requirement would not offset the large margin between the mean RT NDT value for VYNPS at 54 EFPY and the mean RT NDT value for the Clinton plant. Furthermore, given that the mean RT NDT value of 91F forClinton resulted in an NRC-calculated axial weld failure probability of only 2.73 x 10
-6 per reactoryear, it can be concluded that even with the limited-scope coverage of the axial welds, the axial weld failure probability would not exceed 5 x 10
-6 per reactor operating year during the extendedlicense term.The third ISI interval at VYNPS ended during the fall of 2003. Relief for the limited-scope axialweld examination coverage was effective only through the end of the third ISI interval, and it does not authorize reduced examination coverage for the applicable RV axial welds beyond that point.
Therefore, to comply with 10 CFR 50.55a, the applicant must submit a fourth interval ISI relief request for the limited-scope axial weld examination coverage at least 12 months prior to the end of the fourth ISI interval.
4-22The anticipated changes in metallurgical conditions expected over the period of extendedoperation require an additional analysis for 54 EFPY and approval by the NRC to extend the RV axial weld inspection relief through the end of the period of extended operation, on an interval-by-interval basis.4.2.6.3  UFSAR SupplementThe applicant provided a UFSAR Supplement summary description of its TLAA evaluation of RVaxial weld failure probability in LRA Section A.2.2.1.6. which includes:The BWRVIP recommendations for inspection of RV shell welds (BWRVIP-05) are based ongeneric analyses supporting an NRC SER conclusion that the generic-plant axial weld failure rate is no more than 5 x 10
-6 per reactor year as calculated in the BWRVIP-74 SER. BWRVIP-05showed that this axial weld failure rate is orders of magnitude greater than the 40-year end-of-life circumferential weld failure probability and used this analysis to justify relief from inspection of the circumferential welds as described above.The basis for this relief request was a plant-specific analysis that showed thelimiting conditional failure probability for the VYNPS circumferential welds at the end of the original operating term were less than the values calculated in the BWRVIP-05 SER. The BWRVIP-05 SER concluded that the RV failure frequency due to failure of the limiting axial welds in the BWR fleet at the end of 40-years of operation is less than 5 x 10
-6 per reactor year. This failure frequency is dependentupon given assumptions of flaw density, distribution, and location. The failure frequency also assumes that essentially 100 percent of the RV axial welds will be inspected.The BWRVIP-74 SER states it is acceptable to show that the mean RT NDT of thelimiting beltline axial weld at the end of the period of extended operation is less than the limiting value given in the SERs for BWRVIP-74 and BWRVIP-05. The projected 54 EFPY mean RT NDT values for VYNPS are less than the limiting 64 EFPY RT NDT in the analysis performed by the NRC staff (Table 2.6-5 of theBWRVIP-05 SER). As such, this TLAA has been projected to the end of the period of extended operation as required by 10 CFR 54.21(c)(1)(ii).The staff finds that the applicant's UFSAR Supplement summary description for the TLAA of theRV axial weld failure probability appropriately describes how the conditional failure probabilities for the RV axial welds are bounded by the NRC analysis in the staff's supplemental SER dated March 7, 2000. The applicant's UFSAR Supplement summary description is consistent with the staff analysis for the TLAA of the RV axial weld failure probability in Section 4.2.6.2 of this SER.
Based on this assessment, the staff concludes that the UFSAR Supplement summary description for the TLAA of the RV axial weld failure probability is acceptable.On the basis of its review of the UFSAR Supplement, the staff concludes that the summarydescription of the applicant's actions to address RV axial weld failure probability is adequate.
4-234.2.6.4  ConclusionThe staff reviewed the applicant's TLAA of the RV axial weld failure probability, as summarized inLRA Section 4.2.6, including its RAI response dated November 9, 2006, and finds that the applicant appropriately describes how the conditional failure probability for the RV axial welds are bounded by the NRC analysis in the staff supplemental SER on the BWRVIP-05 report, dated March 7, 2000, for the period of extended operation at VYNPS. The staff therefore concludes that the applicant's TLAA in LRA Section 4.2.6 is acceptable.On the basis of its review, as discussed above, the staff concludes that the applicant hasdemonstrated, as required by 10 CFR 54.21(c)(1)(ii), that, for RV axial weld failure probability, the analyses have been projected to the end of the period of extended operation. The staff also concludes that the UFSAR Supplement contains an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).4.3  Metal Fatigue AnalysesFatigue analyses are potential TLAAs for Class 1 and selected non-Class 1 mechanical components. Fatigue is an age-related degradation mechanism caused by cyclic stressing of a component by either mechanical or thermal stresses that become evident by cracking of the component. Fatigue analyses are treated as TLAAs, if based on a set of design transients and on the life of the plant.Fatigue evaluations that meet the definition of TLAA for Class 1 and non-Class 1 mechanicalcomponents are described and evaluated below. Cumulative usage factors (CUFs) have been documented and the actual numbers of design transient cycles have been projected to 60 years.
The CUF sums the fatigue damage from each transient. The ASME Code Section III criterionrequires that the CUF not exceed 1.0. If the CUF is going to exceed 1.0 at the end of the period of extended operation, then the calculation can be refined to reduce the CUF to a value below 1.0.Although some transients are projected to exceed the cycle limits before the end of 60 years, aprogram is in place to track cycles and to provide corrective actions if limits are approached. In addition to metal fatigue analyses, fracture mechanics analyses of flaw indications discoveredduring ISI are TLAAs for those analyses based on time-limited assumptions defined by the current operating term. When a flaw is detected during ISIs, the flawed component can be evaluated for continued service in accordance with ASME Code, Section XI. These evaluations may show the component as acceptable at the end of the current operating term based on predicted inservice flaw growth, typically based on the design thermal and loading cycles.4.3.1  Class 1 FatigueClass 1 components evaluated for fatigue and flaw growth include the RPV and appurtenances,certain RV internals, the reactor recirculation system (RRS), and the reactor coolant system(RCS) pressure boundary. The Class 1 systems include components within the ASME Code, Section XI, SubSection IWB inspection boundary. Fatigue evaluations were performed in the design of the Class 1 components in accordance with the requirements specified in ASME Code, Section III. Fatigue evaluations are contained in analyses and stress reports, and because theyare based on a number of transient cycles assumed for a 40-year plant life, these evaluations are 4-24considered TLAAs. Design cyclic loadings and thermal conditions for the Class 1 components aredefined by the applicable design specifications for each component. The original design specifications provided the initial set of transients used in the design of the components and are included as part of each component analysis or stress report. The component analyses and stress reports contain the fatigue evaluations for each component.4.3.1.1  Reactor Pressure Vessel4.3.1.1.1  Summary of Technical Information in the Application LRA Section 4.3.1.1 summarizes the evaluation of RPV fatigue analyses for the period ofextended operation. These analyses were in accordance with ASME Code, Section III requirements. Design cyclic loadings and thermal conditions for the RPV were defined in its original design specifications, which provided the set of transients used in the design of the components. The applicant modified the transients to reflect actual plant transients more closelyand to make them easier to track while still bounding the original design transients. The Fatigue Monitoring Program will assure that the allowed number of transient cycles is not exceeded by requiring corrective action if transient cycle limits are approached. Consequently, the TLAAs based on those transients will remain valid for the period of extended operation, as required by 10 CFR 54.21(c)(1)(i) or the effects of aging will be adequately managed for the period of extended operation, as required by 10 CFR 54.21(c)(1)(iii).4.3.1.1.2  Staff Evaluation The staff reviewed LRA Section 4.3.1.1 to verify in accordance with 10 CFR 54.21(c)(1)(i), thatthe analyses remain valid for the period of extended operation, or 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended function(s) will be adequately managed for the period of extended operation.The staff reviewed LRA Section 4.3.1.1 against the criteria in SRP-LR Section 4.3.2.1.1.
SRP-LR Section 4.3.2.1.1 stated that for components designed or analyzed to ASMECode Class 1 requirements, the acceptance criteria, depending on the applicant's choice of compliance with 10 CFR 54.21(c)(1)(i), (ii), or (iii), are:(i)The existing CUF calculations remain valid because the number ofassumed transients would not be exceeded during the period of extended operation.(ii)The existing CUF calculations have been reevaluated based on anincreased number of assumed transients to bound the period of extended operation. The resulting CUF remains less than or equal to unity for the period of extended operation.(iii)In Chapter X of the GALL Report, the staff evaluated a program formonitoring and tracking the number of critical thermal and pressure transients for the selected RCS components. As documented in the Audit and Review Report, the staff finds that this program is an acceptable aging management program to address the RCS components metal fatigue 4-25compliance with 10 CFR 54.21(c)(1)(iii). The GALL Report may bereferenced in an LRA and should be treated in the same manner as an approved topical report. In referencing the GALL Report, the applicant should indicate that the referenced material is applicable to the specific plant involved and should provide information necessary to adopt the finding of program acceptability as described and evaluated in the report.
The applicant should also verify that the approvals set forth in the GALL Report for the generic program apply to the applicant's program.The staff reviewed the applicant's TS documentation for RCS heatup/cooldown. Results arefound in the Audit and Review Report. The TS identified that the maximum heatup or cooldown rate is 100F when averaged over any one hour period. Also, the staff reviewed the FatigueMonitoring Program basis document which identified the heatup/cooldown transient with a rate change of 100F/hour. As documented in the Audit and Review Report, the staff reviewed theapplicant's calculation for heatup/cooldown cycles from plant startup in 1972 through 1980. In this calculation, the staff found that some transients may have a temperature rate change exceeding
 
100F/hour. For example, a 60F change in six minutes represents a temperature rate change of 600F/hour. Physically, thermal stress is a function of the rate change of temperature. The higherthe rate the higher the stress.In RAI 4.3-H-03, dated August 1, 2006, the staff requested that the applicant providedocumentation ensuring that the Fatigue Monitoring Program and fatigue analysis addressed and enveloped any operation that may exceed 100F/hour and still meet the heatup/cooldown rate of 100F, when averaged over one hour period. The applicant responded, in a letter datedJanuary 4, 2007, stating that the vessel has been analyzed for 200 heatup/cooldown cycles in which the cooldown transient includes a 1000F/Hr temperature change. On the basis that thestresses derived from 1000F/Hr are conservative, the staff finds the applicant's responseacceptable.In LRA Table 4.3-2, the applicant did not identify the number of design basis cycles for thereactor startup/shutdown transient. The number of transient cycles should be based on the design fatigue analysis. The applicant stated that VYNPS developed a condensed list of transients provided in LRA Table 4.3-2 to simplify cycle tracking by the plant operations staff. Asdocumented in the Audit and Review Report, the staff questioned the range of the condensed list and asked the applicant to provide all the RCS transients. The staff also asked the applicant to demonstrate that the condensed bounding transient list for reactor startup and shutdown envelopes all other RCS transients. The staff further asked the applicant to demonstrate that the CUFs are still within the limit of this revised bounding transient and the allowable number of cycles. In RAI 4.3-H-01, dated August 1, 2006, the staff requested the applicant to provide additional justification to address the condensed transient of reactor startup and shutdown.The applicant responded, in a letter dated September 5, 2006, stating that the original fatigueanalyses were based on 18 transients. The applicant also stated that to improve the process of tracking design transients, the applicant combined some transients and eliminated one transient which resulted in 13 transients. The staff found that the response did not provide sufficient information related to transient cycles and asked applicant to provide additional clarification.
4-26In a letter dated January 4, 2007, the applicant offered additional clarification for RAI 4.3-H-01.The applicant provided actual cycles versus design cycles for all transients and current fatigue usage status. The staff reviewed the applicant's response. On the basis of its review, the staff concludes that the applicant's fatigue tracking and CUFs evaluation are acceptable since the applicant provided the missing gap for its fatigue tracking in the design basis transients.
Therefore, the staff's concern described in RAI 4.3-H-01 is resolved.In addition, during the audit and review, the staff noted that power uprate increased temperatureand pressure values and asked the applicant to explain why its Power Uprate Safety Analysis Report (PUSAR) shows no changes to the stresses between the power uprate fatigue analysis and the original design analysis of all components other than the feedwater (FW) nozzle. The applicant stated that the original stress evaluations were performed at conditions that bound the slight change in conditions for the power uprate and only the FW nozzle had a large enough change in parameters to require a re-calculation of CUF. On the basis of its review of the basis document, the staff finds the applicant's response acceptable.Also, during the audit and review, the staff asked the applicant to address the non-designtransients of the BWR FW nozzle because of bypass flow leakage as described in NUREG-0619.
The staff noted that the number of cycles due to bypass flow leakage for the BWR FW nozzle must be identified in order to perform a valid fatigue analysis for the BWR FW nozzle. If the actual transient was not considered in the CUF evaluation, the staff considers the resulting fatigue CUF to be invalid. In RAI 4.3-H-02, the staff asked the applicant to provide additional justification for excluding this actual transient. In a letter dated September 5, 2006, the applicant provided its response and stated that:As discussed in NUREG-0619, leakage past the FW nozzle thermal sleevestresses the nozzle in two ways. The first is the cold FW leakage past the thermal sleeve as it contacts the nozzle throat behind the thermal sleeve. The second is the rapid movement of the hot/cold interface on the nozzle inner blend radius caused by the mixing of the leakage flow with the hot water in the annulus region.
This second effect is commonly referred to as "rapid mixing" or "rapid thermal cycling" which results in high cycle fatigue.(1) The calculated CUFs for the FW nozzle (shown in LRA Tables 4.3-1 and 4.3-3)include the effect of the FW leakage past the thermal sleeve contacting the nozzle bore. These CUFs do not include the rapid thermal cycling in the nozzle inner blend radius. The CUFs in these tables represent the highest CUFs for the FW nozzle safe end and nozzle throat areas.(2) Rapid thermal cycling affects the CUF of the FW nozzle inner blend radius;however, this effect is not included in the calculation of the CUF for the nozzle inner blend radius. VYNPS has conservatively assumed that fatigue cracks may be present in the clad. Subsequent system cycling could cause these surface cracks to grow into the nozzle base metal. VYNPS manages this cracking by performing periodic inspections that were implemented in response to GL 80-095 and 4-27NUREG-0619. The inspection frequency is based on a calculated fatigue crackgrowth rate of a postulated flaw in the nozzle inner blend radius. The NRC previously reviewed and approved this approach to handling FW nozzle inner blend radius cracking. (Letter D.H. Dorman (USNRC) to D.A Reid (VYNPS),
 
==Subject:==
Evaluation of Request for Relief from NUREG-061 9 for VYNPS dated 2/6/95, (TAC No. M88803))The VYNPS flaw growth calculation uses methods in compliance with GE BWROwners Group Topical Report "Alternate BWR Feedwater Nozzle Inspection Requirements," GE-NE-523-A71 -0594, Revision 1, August 1999, and the NRC Final Safety Evaluation (TAG No. MA6787) dated March 10, 2000. The FW nozzle inspection interval is based on 20 percent of the time required for a postulated 0.25 inch flaw in the base metal to grow to 10 percent of the nozzle wall thickness, or a maximum of 6-years (4 operating cycles).Rapid thermal mixing has some effect on the base metal of the FW nozzle;however, the associated temperature changes are so rapid that they do not propagate deeply into the base metal. In fact, NUREG-0619, Section 2.2, states:
"From analysis and from experience in repairing FW nozzles, it is known that high cycle thermal fatigue cracks propagate to a depth of about 1/4 inch before the cyclic thermal stress amplitude attenuates to a an insignificant level." Unlike many BWRs, VYNPS has not removed the 3/16 inch stainless steel cladding from the inner blend radius. The effect of the rapid thermal cycling is largely in the cladding, affecting approximately 1/16 inch of the base metal (not an exact value because of the different heat transfer properties of the clad and the base metal). While NUREG-0619 documents that the cladding is more likely to crack than the unclad base metal, the cladding does keep the thermal stresses from penetrating as deeply into the base metal. The staff reviewed the applicant's response. The staff finds that the applicant had conservativelypostulated the 0.25-inch cracking in FW fatigue and crack growth analysis and provided adequate inspection programs to manage cracking in addition to its Fatigue Monitoring Program.
Therefore, the staff's concern described in RAI 4.3-H-02 is resolved.The staff reviewed the fatigue results for the RV components in LRA Table 4.3-1. When the40-year CUFs were multiplied by 1.5 (60yrs /40yrs), the RV components, except FW nozzle and reactor recirculation (RR) outlet nozzle, have CUFs less than 1.0 for the 60-year plant life. On this basis, the staff concludes that the RV components, other than FW nozzle and RR outlet nozzle, meet the requirement of 10 CFR 54.21(c)(1)(ii). The environmental assisted fatigue assessment is discussed further in SER Section 4.3.3.2.In a letter dated January 4, 2007, the applicant provided additional clarification for the 60-yearprojected CUF. In its letter, the applicant clarified that the 40-year design analysis CUF for the RR outlet nozzle safe end is 0.807 and RR outlet nozzle safe end was replaced in 1986. Therefore, the 60-year design CUF will be based on a linear projection by multiplying the 40-year CUF with 1.15 (46yrs /40yrs). The staff finds that the CUF for RR outlet nozzle safe end will be 0.928, which should remain valid for the period of extended operation. The staff finds that the applicant's approach is acceptable and meets the requirement of 10 CFR 54.21(c)(1)(i).
4-28The staff reviewed the applicant's Fatigue Monitoring Program and documented its acceptance inSER Section 3.0.3.2.10. In addition to the Fatigue Monitoring Program, the applicant also identified additional aging monitoring items that may be used to manage fatigue. The staff finds this acceptable and that the applicant meets the requirements of 10 CFR 54.21(c)(1)(iii).4.3.1.1.3  UFSAR Supplement The applicant provided a UFSAR Supplement summary description of its TLAA evaluation of RPVfatigue analyses in LRA Section A.2.2.2.1. On the basis of its review of the UFSAR Supplement, the staff concludes that the summary description of the applicant's actions to address RPV fatigue analyses is adequate.4.3.1.1.4  Conclusion On the basis of its review, as discussed above, the staff concludes that the applicant hasdemonstrated that the RPV fatigue analyses will remain valid for the period of extended operation, in compliance with 10 CFR 54.21(c)(1)(i). The staff concludes that the applicant has demonstrated that the RPV fatigue analyses have been projected through the period of extended operation, in compliance with 10 CFR 54.21(c)(1)(ii). The staff also concludes that the applicant has demonstrated that the effects of aging on the intended function(s) of the RPV will be adequately managed for the period of extended operation, in compliance with 10 CFR 54.21(c)(1)(iii). The staff also concludes that the UFSAR Supplement contains an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).4.3.1.2  Reactor Vessel Internals4.3.1.2.1  Summary of Technical Information in the Application LRA Section 4.3.1.2 summarizes the evaluation of RV internals fatigue analysis for the period ofextended operation. Although not mandated, the design of the RV internals is in accordance with the intent of ASME Code, Section III. In a letter dated August 7, 1996, "Response to RequestAdditional Information Regarding VYNPS Core Shroud Modification," VYNPS stated that a fatigue analysis had been performed for the shroud repair hardware and this calculation included a fatigue analysis of the slotted hole in the shroud support plate where the shroud repair ligaments are attached. The resulting CUF was 0.23 based on the numbers of design transients in the original RV design report. This analysis is treated as a TLAA. The Fatigue Monitoring Program for VYNPS will assure that the allowed number of transientcycles is not exceeded by requiring corrective action if transient cycle limits are approached.
Consequently, the TLAAs based on those transients will remain valid for the period of extended operation, as required by 10 CFR 54.21(c)(1)(i), or aging effects on the intended function(s) will be adequately managed for the period of extended operation, in compliance with 10 CFR 54.21(c)(1)(iii).
4-294.3.1.2.2  Staff EvaluationThe staff reviewed LRA Section 4.3.1.2 to verify in accordance with 10 CFR 54.21(c)(1)(i), thatthe analyses remain valid for the period of extended operation, or 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended function(s) will be adequately managed for the period of extended operation.The staff reviewed the applicant's TLAA basis document and UFSAR Section K.3.1. UFSARSection K.3.1 stated that the core shroud repair was designed for a 40-year life. The staff agrees that the core shroud repair fatigue is a TLAA. The staff reviewed the applicant's power uprate re-evaluation of the core shroud repair. The CUFs for the shroud repair as listed in LRA Table 4.3-1 are 0.23 and 0.12, which are well below 1.0. On this basis, the TLAA (fatigue analysis) based on those transients will remain valid for the period of extended operation, as required by 10 CFR 54.21(c)(1)(i). The Fatigue Monitoring Program will assure that the allowed number of transient cycles will not be exceeded and will be used to manage the effects of aging on the intended function(s) for the period of extended operation, as required by 10 CFR 54.219(c)(1)(iii). Therefore, the core shroud repair fatigue TLAA is acceptable.4.3.1.2.3  UFSAR Supplement The applicant provided a UFSAR Supplement summary description of its TLAA evaluation of RVinternals in LRA Section A.2.2.2.1. On the basis of its review of the UFSAR Supplement, the staff concludes that the summary description of the applicant's actions to address RV internals is adequate.4.3.1.2.4  Conclusion On the basis of its review, as discussed above, the staff concludes that the applicant hasdemonstrated that the RV internals fatigue analyses will remain valid for the period of extended operation, in compliance with 10 CFR 54.21(c)(1)(i). The staff also concludes that the applicant has demonstrated that the effects of aging on the intended function(s) of the RV internals will be adequately managed for the period of extended operation, in compliance with 10 CFR 54.21(c)(1)(iii). The staff also concludes that the UFSAR Supplement contains an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).4.3.1.3  Class 1 Piping and Components4.3.1.3.1  Summary of Technical Information in the Application LRA Section 4.3.1.3 summarizes the evaluation of Class 1 piping and components for the periodof extended operation. The applicant, in 1986, replaced RR system piping and connecting portions of the residual heat removal (RHR) system piping. The new piping was designed and analyzed to ANSI B31.1 but inspected and tested to ASME Code, Section III requirements. Stressanalyses for the RRS were to ANSI B31.1 requirements. Even though ANSI B31.1 does not require it, there was a fatigue analysis for the highest anticipated usage factor location, the RHR to RR tee. These analyses were based on a number of cycles which are not expected to be exceeded in 40-years and as such are treated as TLAAs.
4-30The Fatigue Monitoring Program will assure that the allowed number of transient cycles is notexceeded by requiring corrective action if transient cycle limits are approached. Consequently, the TLAA based on those transients will remain valid, or the effects of aging on the intended function(s) will be adequately managed, for the period of extended operation.UFSAR Section 4.6.3 states that the main steam isolation valves (MSIVs) are designed for40-years based on 100 cycles of operation the first year and 50 cycles of operation per year thereafter. This statement may be interpreted to infer a TLAA that will remain valid through the period of extended operation, as required by 10 CFR 54.21(c)(1)(i). The MSIVs will not exceed 2050 cycles in 60-years (34 cycles per year).4.3.1.3.2  Staff Evaluation The staff reviewed LRA Section 4.3.1.3 to verify in accordance with 10 CFR 54.21(c)(1)(i), thatthe analyses remain valid for the period of extended operation.The staff reviewed the technical information in LRA Section 4.3.1.3, on the fatigue analysis ofClass 1 piping and components. The applicant indicated that the piping stress analyses wereperformed to ANSI B31.1 requirements and an additional fatigue analysis was done for the highest anticipated usage factor location, the RHR to RR tee. The staff noted that in LRA Table 4.3-1, the applicant stated that the plant-specific CUFs were not found for the RR piping tee and asked the applicant to clarify the difference between LRA Section 4.3.1.3 and LRA Table 4.3-1.The applicant stated that the statement was made as part of the GE template for thesecalculations, since many plants were replacing the RR piping in accordance with ASME Code, Section III. VYNPS replaced their piping to meet requirements of ANSI B31.1 rather than theASME Code, Section III requirements. No plant-specific fatigue analysis was performed forVYNPS. In a letter dated July 14, 2006, the applicant revised its LRA to address the above issue.
In this letter, the applicant stated that stress analyses for the RRS were performed to meet ANSI B31.1 standards, which do not require a detailed fatigue analysis that calculates a CUF, but allows up to 7000 cycles with a stress reduction factor of 1.0 in the stress analyses. The applicant also stated that the 7000 thermal cycle assumption is valid and bounding for 60-years of operation. The staff reviewed the RCS transients and concludes that 7000 thermal cycle for the 60-years of operation is valid. On this basis, the staff finds the applicant's response acceptable.The staff asked the applicant to identify the design code and the number of operating cycles forthe MSIVs. The applicant stated that the MSIVs were built to the ASME Code. The applicant reviewed the plant operating records and estimated that there were 587 operations of the MSIVs in 35-years of operation. Extrapolating this number to 60-years of operation (considering changes in surveillance testing of the valves) yields 785 cycles. This is well below the design value of 2050 cycles for these valves as indicated in UFSAR Section 4.6.3. On this basis, the staff finds the fatigue assessment for the MSIVs for VYNPS to be acceptable, in accordance with 10 CFR 54.21(c)(1)(i).
4-314.3.1.3.3  UFSAR SupplementThe applicant provided a UFSAR Supplement summary description of its TLAA evaluation ofClass 1 piping and components in LRA Section A.2.2.2.1. On the basis of its review of the UFSAR Supplement, the staff concludes that the summary description of the applicant's actions to address Class 1 piping and components is adequate.4.3.1.3.4  Conclusion On the basis of its review, as discussed above, the staff concludes that the applicant hasdemonstrated, in compliance with 10 CFR 54.21(c)(1)(i), that, for Class 1 piping and components, the analyses remain valid for the period of extended operation. The staff also concludes that the UFSAR Supplement contains an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).4.3.2  Non-Class 1 Fatigue 4.3.2.1  Summary of Technical Information in the ApplicationLRA Section 4.3.2 summarizes the evaluation of non-Class 1 fatigue for the period of extendedoperation. The design of ASME Code III Class 2 and 3 piping systems in corporates the codestress reduction factor for determining acceptability of piping design for thermal stresses. The design of ANSI B31.1 Code components also incorporates stress reduction factors based upon an assumed number of thermal cycles. In general, 7000 thermal cycles are assumed for a stress reduction factor of 1.0 in the stress analyses. The applicant's evaluation of the validity of this assumption for 60-years of plant operation indicates that the 7000 thermal cycle assumption is valid and bounding for 60-years of operation; therefore, the pipe stress calculations are valid for the period of extended operation as required by 10 CFR 54.21(c)(1)(i).Some applicants for license renewal have estimated that piping in the primary sampling systemwill have more than 7000 thermal cycles before the end of the period of extended operation. The sampling system takes reactor coolant samples every 96 hours during normal operation; however, the normal samples are taken from the RWCU filter influent, where the water already has been cooled. Thus, normal sampling does not cause a thermal cycle. Alternate samples may be taken directly from the B discharge header of the RRS via containment penetration X-41; however, this procedure is infrequent and this piping, designed to ANSI B31.1, will not exceed 7000 cycles prior to 60-years of operation.4.3.2.2  Staff EvaluationThe staff reviewed LRA Section 4.3.2 to verify in accordance with 10 CFR 54.21(c)(1)(i), that theanalyses remain valid for the period of extended operation.The staff reviewed the technical information in LRA Section 4.3.2, pertaining to the non-Class 1fatigue analysis of piping, against the criteria contained in SRP-LR Section 4.3.2.1.2 and documented the results in the Audit and Review Report.
4-32SRP-LR Section 4.3.2.1.2.1 stated that for piping designed or analyzed to ANSI B31.1 standards,the acceptance criteria is the existing fatigue strength reduction factors remain valid because the number of cycles would not be exceeded during the period of extended operation.Although ANSI B31.1 Code does not require explicit fatigue analysis, it considers fatigue implicitlyin the design calculation by applying an allowable stress range reduction factor. Fatigue also can depend on the number of design thermal expansion cycles.The staff reviewed the applicant's basis document which provided the basis and calculations forthe metal fatigue. In the basis document, the applicant discussed the operating cycles for all the systems, including RHR, automatic depression system, high pressure coolant injection, reactor core isolation coolant, emergency diesel generator, and fire protection. The applicant concluded that these systems have experienced far less than 7000 thermal cycles for 60-years of operation.On the basis of its audit and review, the staff concludes that the number of thermal cycles forANSI B31.1 piping systems is less than 7000 for 60-years operation. Therefore, the existing ANSI B31.1 piping analysis will remain valid for the period of extended operation, as required by 10 CFR 54.21(c)(1)(i).In addition, the staff requested that the applicant clarify the statement related to the design ofASME Code, Section III, Class 2 and 3 piping systems. The applicant stated that VYNPS doesnot have any ASME Code, Section III, Class 2 and 3 piping systems and that all the pipingsystems are designed in accordance with ANSI B31.1 requirements. In a letter dated July 14, 2006, the applicant provided an LRA amendment to clarify this issue. In this letter, the applicant revised ASME Code, Section III, Class 2 and 3 piping systems designation to safetyClass 2 and 3 piping systems. The staff finds this change is acceptable.4.3.2.3  UFSAR SupplementThe applicant provided a UFSAR Supplement summary description of its TLAA evaluation ofnon-Class 1 fatigue in LRA Section A.2.2.2.2. which stated that:"For non-Class 1 components identified as subject to cracking due to fatigue, areview of system operating characteristics was conducted to determine the approximate frequency of any significant thermal cycling. If the number of equivalent full temperature cycles for 60-years of operation is below 7000 cycles, the component is acceptable for the period of extended operation. If the number of equivalent full temperature cycles exceeds 7000, the individual stress calculationsrequire further evaluation. No components were identified with projected cycles exceeding 7000. Therefore, the TLAA for non-Class 1 piping and components remain valid for the period of extended operation in compliance with 10 CFR 54.21(c)(i)."On the basis of its review of the UFSAR Supplement, the staff concludes that the summarydescription of the applicant's actions to address non-Class 1 fatigue is adequate, as required by 10 CFR 54.21(d).
4-334.3.2.4  ConclusionOn the basis of its review, as discussed above, the staff concludes that the applicant hasdemonstrated, as required by 10 CFR 54.21(c)(1)(i), that, for non-Class 1 fatigue, the analyses remain valid for the period of extended operation. The staff also concludes that the UFSAR Supplement contains an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).4.3.3  Effects of Reactor Water Environment on Fatigue Life 4.3.3.1  Summary of Technical Information in the ApplicationLRA Section 4.3.3 summarizes the evaluation of effects of reactor water environment on fatiguelife for the period of extended operation. NUREG/CR-6260 applies fatigue design curves incorporating environmental effects on several plants and identifies locations of interest for consideration of environmental effects with the following six component locations as most sensitive to them:    (1)reactor vessel shell and lower head    (2)reactor vessel feedwater nozzle (3)reactor recirculation piping (including inlet and outlet nozzles)
  (4)core spray line reactor vessel nozzle and associated piping (5)RHR return piping (6)feedwater pipingEntergy evaluated the limiting locations (a total of nine components corresponding to the six mostsensitive locations) with the guidance of the GALL Report, Volume 2, Section X.M.1. Seven of nine components evaluated have an environmentally adjusted CUF of greater than 1.0. The ASME Code does not require environmental adjustment for fatigue analyses. Considering environmental effects prior to the period of extended operation, for each location thatmay exceed a 1.0 CUF the applicant will implement one or more of the following: (1) further refinement of the fatigue analyses to lower the predicted CUFs to less than 1.0;(2) management of fatigue at the affected locations by an inspection program reviewed and approved by the staff; or (3) repair or replacement of the affected components.Should VYNPS select the option to manage environmental-assisted fatigue during the period ofextended operation, details of the aging management program such as scope, qualification, method, and frequency will be provided to the NRC prior to the period of extended operation. The effects of environmental-assisted thermal fatigue for the limiting locations identified in NUREG-6260 have been evaluated. Cracking by environmentally-assisted fatigue of these locations will be addressed by one or more of these three approaches in compliance with 10 CFR 54.21(c)(1).
4-344.3.3.2  Staff EvaluationThe staff reviewed LRA Section 4.3.3 to verify: (1) in accordance with 10 CFR 54.21(c)(1)(i), thatthe analyses remain valid for the period of extended operation; (2) in accordance with 10 CFR 54.21(c)(1)(ii), that the analyses have been projected to the end of the period of extended operation; and (3) in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended function(s) will be adequately managed for the period of extended operation.The staff reviewed the technical information in LRA Section 4.3.3, pertaining to the effect ofreactor water environment on the fatigue analysis of components and piping, against the criteria contained in SRP-LR Section 4.3.3.2.SRP-LR Section 4.3.3.2 stated that the applicant must address the staff recommendation forclosure of General Safety Issue (GSI)-190 and also address the effects of the coolant environment on component fatigue life when aging management programs are formulated to support license renewal. If an applicant has chosen to assess the impact of the reactor coolant environment on a sample of critical components, the applicant shall address the following:  (a)The critical components include, as a minimum, those selected in NUREG/CR-6260.
  (b)The sample of critical components has been evaluated by applying environmentalcorrection factors, F en, to the existing ASME Code fatigue usage factor.  (c)Formulas for calculating the environmental life correction factors are those contained inNUREG/CR-6583 for carbon and low-alloy steels, and in NUREG/CR-5704 for austenitic stainless steels (SSs), or an approved technical equivalent.The staff verified that the applicant included into the environmental assisted fatigue evaluation allthe critical components selected in NUREG/CR-6260. LRA Table 4.3-3 indicated that the sample of critical components has been evaluated by applying environmental correction factors to the existing ASME Code fatigue analysis, except for RR piping tee, core spray (CS) safe end, RHR return piping, and FW piping. The staff also verified the formulas for calculating the environmental life correction factors. Since the formulas follow SRP-LR guidance, they are acceptable.During the audit and review, the staff noted that the CUFs for the components of CS safe end,FW piping, RHR return piping, and RR piping tee, in LRA Tables 4.3-1 and 4.3-3, are taken from NUREG/CR-6260 and not based on plant-specific analysis results. Staff requested that the applicant provide justification for not using plant-specific analysis results. In a letter dated July 14, 2006, the applicant revised its LRA to address this issue. In this letter, the applicant stated that LRA Table 4.3-1 has been revised to remove the NUREG/CR-6260 values for CS safe end, FW piping, RHR return piping, and RR piping tee and replaced them with "not applicable."
The staff finds that CUFs for these four locations are required to address the effects of reactor coolant environment on fatigue as mentioned above.The staff reviewed the applicant's Commitment #27, which was provided in a letter datedJuly 6, 2006, and LRA question and answer (Q&A) database Item 318. In the LRA Q&A database Item 318, the applicant stated that the more limiting, VYNPS-specific locations, with a valid CUF may be substituted for the NUREG/CR-6260 locations. The staff did not find the substitution 4-35proposed by the applicant acceptable since SRP-LR clearly stated that "the critical componentsinclude, as a minimum, those selected in NUREG/CR-6260." The staff asked whether the applicant will address all nine locations instead of substitutions. In a letter dated January 4, 2007, the applicant provided its revised Commitment #27. The applicant stated that more limiting VYNPS-specific locations with a valid CUFs may be added in addition to the NUREG/CR-6260 locations to address the effects of the coolant environment. Since the applicant will address more locations than the minimum required by NUREG/CR-6260, the staff finds applicant's response acceptable.The staff requested that the applicant clarify whether oxygen concentrations derived fromimplementation of normal water chemistry (NWC) were factored in the environmental fatigue life correction factor (F en) calculations for those operational periods when NWC was implementedinstead of hydrogen water chemistry (HWC). The applicant stated that F en was estimated basedon (HWC) oxygen concentration. Prior to the period of extended operation, VYNPS will perform fatigue analyses and an appropriate F en will be used to account for operating times when bothHWC and NWC are implemented. On the basis of its review, the staff finds this acceptable.The applicant indicated that seven of nine components reviewed have an environmentallyadjusted CUF of greater than 1.0 as indicated in LRA Table 4.3-3. For each location that may exceed a CUF of 1.0 when considering environmental effects prior to entering the period of extended operation, VYNPS will implement one or more of the following options:  (1)further refinement of the fatigue analyses to lower the predicted CUFs to less than 1.0; (2)management of fatigue at the affected locations by an inspection program that has beenreviewed and approved by the NRC (e.g., periodic non-destructive examination of the affected locations at inspection intervals determined by a method acceptable to the NRC);  (3)repair or replacement of the affected locations.
The staff finds that the original fatigue evaluations were analyzed based on the design transients.The applicant has plant-specific operating transient data that could be used to refine the fatigue analyses to remove the conservatism which was assumed during the design stage. The applicant also could use later developments in the ASME Code fatigue assessment to lower the CUF. On the above mentioned basis, the staff finds that option (1) is acceptable.ASME Code, Section XI, IWB-3740(a) states that "Appendix L provides procedures that may beused to assess the effects of thermal and mechanical fatigue concerns on component acceptab}}

Latest revision as of 18:06, 14 January 2025

Safety Evaluation Report, Related to the License Renewal of Vermont Yankee Nuclear Power Station
ML080440179
Person / Time
Site: Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date: 01/31/2008
From: Rowley J
NRC/NRR/ADRO/DLR
To:
Rowley J, NRR/DLR/RLRB, 415-4053
References
Download: ML080440179 (770)
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