ML080720639: Difference between revisions

From kanterella
Jump to navigation Jump to search
(Created page by program invented by StriderTol)
(StriderTol Bot change)
 
(3 intermediate revisions by the same user not shown)
Line 3: Line 3:
| issue date = 02/29/2008
| issue date = 02/29/2008
| title = Compare Vermont Yankee SER with Hole (Dec 2007) to Vermont Yankee FSER (Feb 2008)
| title = Compare Vermont Yankee SER with Hole (Dec 2007) to Vermont Yankee FSER (Feb 2008)
| 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 =  
Line 15: Line 15:


=Text=
=Text=
{{#Wiki_filter:Safety Evaluation Report Related to the License Renewal of Vermont Yankee Nuclear Power Station Docket No. 50-271Entergy Nuclear Operations, Inc.
{{#Wiki_filter:}}
U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation January 2008 February 2008
>
THIS PAGE INTENTIONALLY LEFT BLANK.
iii ABSTRACT This safety evaluation report (SER) documents t he technical review of the Vermont Yankee Nuclear 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 Operating Licenses 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 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 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 October>January XX February 21
, 2007  2008, the cutoff date for consideration in the SER. The staff
>identified six confirmatory 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.
THIS PAGE INTENTIONALLY LEFT BLANK.
v TABLE OF CONTENTSAbstract...................................................................iiiTable of Contents............................................................vAbbreviations........................................................xiii Introduction and General Discussion...........................................1-1 1.1  Introduction.....................................................1-1
 
===1.2 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.............................................1-6
 
===1.5 Summary===
of Open Items...........................................1-71.6  Summary of Confirmatory Items.....................................1-7
 
===1.7 Summary===
of Proposed License Conditions.............................1-9 Structures and Components Subject to Aging Management Review...................2-1
 
===2.1 Scoping===
and Screening Methodology.................................2-1 2.1.1  Introduction..............................................2-12.1.2  Summary of Technical Information in the Application..............2-1
 
====2.1.3 Scoping====
and Screening Program Review.......................2-2 2.1.3.1  Implementation Procedures and Documentation Sources for Scoping 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.........2-21 2.1.4.5  Mechanical Component Scoping.....................2-24 2.1.4.6  Structural Component Scoping......................2-27 2.1.4.7  Electrical Component Scoping.......................2-28 2.1.4.8  Conclusion for Scoping Methodology..................2-29
 
====2.1.5 Screening====
Methodology...................................2-29 2.1.5.1  General Screening Methodology.....................2-29 2.1.5.2  Mechanical Component Screening...................2-30 2.1.5.3  Structural Component Screening.....................2-32 2.1.5.4  Electrical Component Screening.....................2-33 2.1.5.5  Conclusion for Screening Methodology................2-352.1.6  Summary of Evaluation Findings............................2-352.2  Plant-Level Scoping Results.......................................2-36 2.2.1  Introduction.............................................2-36 vi2.2.2  Summary of Technical Information in the Application.............2-362.2.3  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..................2-46
 
====2.3.2 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............................2-56 2.3.2.7  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.................................2-702.3.3.6  Fuel Oil.........................................2-732.3.3.7  Instrument Air....................................2-75 2.3.3.8  Fire Protection-Water..............................2-77 2.3.3.9  Fire Protection-Carbon Dioxide......................2-89 2.3.3.10  Heating, Ventilation, and Air Conditioning.............2-94 2.3.3.11  Primary Containment Atmosphere Control / Containment Atmosphere Dilution...............................2-96 2.3.3.12  John Deere Diesel..............................2-101 2.3.3.13  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.......................2-117 2.3.3.13M Reactor Water Clean-Up........................2-1182.3.3.13N Stator Cooling ................................2-121 2.3.3.13O HD & HV Instruments...........................2-122 2.3.3.13P Air Evacuation ................................2-123 2.3.3.13Q Building (Drainage System Components) ...........2-124 vii2.3.3.13R Circulating Water Priming .......................2-1242.3.3.13S Extraction Steam ..............................2-125
 
2.3.3.13T Heater Drain ..................................2-1262.3.3.13U 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......................2-135 2.3.4.1  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)....................................2-139
 
===2.4 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.....................................2-154
 
===2.5 Scoping===
and Screening Results: Electrical and Instrumentation and Control Systems 2-1542.5.1  Summary of Technical Information in the Application............2-155
 
====2.5.2 Staff====
Evaluation.........................................2-156 2.5.3  Conclusion............................................2-159
 
===2.6 Conclusion===
for Scoping and Screening..............................2-160Aging Management Review Results............................................3-13.0  Applicant's Use of the Generic Aging Lessons Learned Report.............3-1 viii3.0.1  Format of the License Renewal Application.....................3-2 3.0.1.1  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................................3-6 3.0.2.4  Documentation and Documents Reviewed..............3-63.0.3  Aging Management Programs...............................3-73.0.3.1  AMPs Consistent with the GALL Report...............3-10 3.0.3.2  AMPs Consistent with the GALL Report with Exceptions and/orEnhancements...................................3-41 3.0.3.3  AMPs Not Consistent with or Not Addressed in the GALL Report..............................................3-110
 
====3.0.4 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.....................................3-148
 
===3.1 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.........3-168 3.1.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended........................3-180 3.1.2.3  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.........3-210 3.2.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended........................3-220 3.2.2.3  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.........3-262 3.3.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended........................3-296 3.3.2.3  AMR Results Not Consistent with or Not Addressed in the GALLReport.........................................3-3193.3.3  Conclusion............................................3-361
 
===3.4 Aging===
Management of Steam and Power Conversion Systems...........3-3613.4.1  Summary of Technical Information in the Application............3-361 ix3.4.2  Staff Evaluation.........................................3-3613.4.2.1  AMR Results Consistent with the GALL Report.........3-372 3.4.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended........................3-380 3.4.2.3  AMR Results Not Consistent with or Not Addressed in the GALLReport.........................................3-3893.4.3  Conclusion............................................3-393
 
===3.5 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.........3-408 3.5.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended........................3-428 3.5.2.3  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.........3-480 3.6.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended........................3-482 3.6.2.3  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.................................................4-1
 
===4.1 Identification===
of Time-Limited Aging Analyses...........................4-14.1.1  Summary of Technical Information in the Application..............4-1
 
====4.1.2 Staff====
Evaluation...........................................4-2 4.1.3  Conclusion..............................................4-24.2  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......................................4-104.2.3  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............................4-13 x4.2.4.1  Summary of Technical Information in the Application.....4-134.2.4.2  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......................................4-23
 
===4.3 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......................................4-33
 
====4.3.3 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.............................................4-40
 
===4.5 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.............................................4-41
 
===4.6 Containment===
Liner Plate, Metal Containment, and Penetrations Fatigue Analysis.....................................................4-41
 
====4.6.1 Fatigue====
of the Torus......................................4-414.6.1.1  Summary of Technical Information in the Application.....4-41 4.6.1.2  Staff Evaluation..................................4-42
 
4.6.1.3  UFSAR Supplement...............................4-424.6.1.4  Conclusion......................................4-42
 
====4.6.2 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 xi 4.6.2.3  UFSAR Supplement...............................4-444.6.2.4  Conclusion......................................4-44
 
====4.6.3 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........................4-50 4.7.2.4  BWRVIP-47, Lower Plenum Fatigue Analysis...........4-51 4.7.2.5  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..........................4-55 Review by the Advisory Committee on Reactor Safeguards.........................5-1Conclusion...............................................................6-1 Appendix A:  VYNPS License Renewal Commitments.............................A-1 Appendix B:  Chronology....................................................B-1Appendix C:  Principal Contributors............................................C-1 Appendix D:  References....................................................D-1 Tables Table 1.4-1  Current Interim Staff Guidance...................................1-7Table 3.0.3-1  VYNPS Aging Management Programs..............................3-7 Table 3.1-1  Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor CoolantSystem Components in the GALL Report.....................................3-150 Table 3.2-1  Staff Evaluation for Engineered Sa fety Features Systems Components in the GALL xiiReport.................................................................3-201 Table 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...................3-287 Table 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...3-460 Table 3.6-1  Staff Evaluation for Electrical and I&C Components in the GALL Report...3-477 ABBREVIATIONSAACalternate ACACalternating current ACARaluminum conductor alloy reinforced ACIAmerican Concrete Institute ACRSAdvisory Committee on Reactor Safeguards ACSalternate cooling system ACSRaluminum core steel reinforced xiiiADAMSAgencywide Document Access and Management SystemADSautomatic 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
 
CFR Code of Federal RegulationsCIconfirmatory item CLBcurrent licensing basis CMAACrane Manufactures Association of America
 
CO 2 carbon dioxideCPPUconstant pressure power uprate CRLcomponent record list CRDcontrol rod drive CRGTcontrol rod guide tube CScore spray CSScore spray system xivCSCScore 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 Research Institute EPRI-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 en environmental fatigue life correction factorFERCFederal Energy Regulatory Commission FFflency factor FIVflow-induced vibration FOfuel oil FPCfuel pool cooling FPFDfuel pool filter-demineralizer
 
FR Federal RegisterFSARfinal safety analysis report ft-lbfoot-pound FWfeedwaterGALLGeneric Aging Lessons Learned ReportGDCgeneral design criteria or general design criterion xvGEGeneral ElectricGEISGeneric 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 ISTinservice 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 xviLRPGlicense 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 2 nitrogenNaOHsodium hydroxide NBnuclear boiler NBVISnuclear boiler vessel instrumentation system
 
n/cm 2 neutrons 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 itemPASSpost-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 assurance xviiQ&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 NDT reference 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 SLCstandby liquid control SOseal oil SPL sampling SOCstatement of consideration SRPStandard Review Plan SRP-LRStandard Review Plan for Review of License Renewal Applications for Nuclear Power PlantsSRVsafety relief valve SSstainless steel SSCsystem, structure, and component SSEsafe-shutdown earthquake SWservice water SWSservice water systemsTBCCWturbine building closed cooling water xviiiTGturbine generatorTLAAtime-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 1 INTRODUCTION AND GENERAL DISCUSSION
 
===1.1 Introduction===
This document is a safety evaluation report (SER) on the license renewal application (LRA) for Vermont 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 of Federal Regulations , "Requirements for Renewal of Operating Licenses for Nuclear Power Plants" (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 Renewal US Nuclear Regulatory Commission
 
Washington, DC 20555-0001
 
Attention: Jonathan Rowley, Mail Stop 011-F1 In its January 25, 2006 submission letter, the applicant requested renewal of the operating license 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 safety issues 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 requests
 
for 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 February 21 , 2008. The staff reviewed
>information received 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
 
(301-415-4737 / 800-397-4209), and at Dickinson Memorial Library, 115 Main St., Northfield, 1-2 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 the technical 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 considered during 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 to NUREG-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 Background Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating
 
licenses for commercial power reactors are issued for 40 years. These licenses can be renewed
 
for up to 20 additional years. The original 40-year license term was selected on the basis of
 
economic and antitrust considerations, rather than on technical limitations; however, some
 
individual plant and equipment designs may have been engineered based on an expected
 
40-year service life.
In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear power plant aging. This workshop led the NRC to establish a comprehensive program plan for nuclear
 
plant aging research. 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.
In 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 staff participated in an industry-sponsored demonstration program to apply 10 CFR Part 54 to a pilot
 
plant and to gain experience necessary to dev elop implementation guidance. To establish a scope of review for license renewal, 10 CFR Part 54 defined age-related degradation unique to 1-3 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 Review License renewal requirements for power reactors are based on two key principles:  (1)The regulatory process is adequate to ensure that the licensing bases of all currently operating plants 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 the same 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 license renewal 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 the scope 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
 
maintained consistent with the current licensing basis (CLB) for the period of extended
 
operation. However, active equipment is considered to be adequately monitored and maintained
 
by existing programs. In other words, 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 1-4 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 must have 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 and Content 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 progr ams (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====
Review Part 51 of 10 CFR governs environmental protection regulations. In December 1996, the staff revised the environmental protection regulations to facilitate the environmental review for
 
license renewal. The staff prepared the Generic Environmental Impact Statement (GEIS) to document its evaluation of the possible environm ental 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
 
Environmental 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).
1-5 In accordance with the National Environmental Policy Act of 1969 and 10 CFR Part 51, the staff reviewed the plant-specific environmental impac ts 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 Matters Part 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 submit general 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 changes to 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 in Item 3 of the attachment to the agreement, which is the last to expire. Item 3 of
 
the attachment to the indemnity agr eement, 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.
In accordance with 10 CFR 54.21,"Contents of Application - Technical Information," the NRC requires 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 of 1-6 the 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 NRC requires that the LRA include changes or additions to the technical specifications necessary to
 
manage 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 in accordance 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," the ACRS 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 the environmental 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 Guidance License 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 main taining 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 sections in which the staff addresses them.
Table 1.4-1  Current Interim Staff Guidance 1-7 ISG Issue(Approved ISG Number)PurposeSER SectionNickel-alloy components in the reactor coolant pressure boundary (LR-ISG-19B)Cracking of nickel-alloy componentsin 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 Items As a result of its review of the LRA, including additional information submitted to the staff through 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 Items As 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-1 License renewal drawing LRA-G-191159-SH-01-0, at location H-11, depicts pipe section 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 - NRC License Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety 1-8 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 inspection team 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 CI 2.3.3.2a-1 is resolved.
>CI 2.3.3.2a-2 LRA Section 2.1.2.1.2 states in part that 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. 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 , a drain line).
It is not clear whether the nonsafety-related piping systems were included up to 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).
In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License 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 2 1-9 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 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 finds the above response acceptable because the applicant>stated that NRC Regional Inspection Team found 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. Furthermore, the staff again
>reviewed the applicable LRA drawings for component types that may have been omitted from
 
Table 2.3.3-13-42 and found all component types have been added to LRA in Table>2.3.3-13-42 3-13-42 to be consistent with the component types included within the scope of
>license renewal at similar facilities. Therefore, the staff concern described in Inspection Item CI>2.3.3.2a--2 is resolved.
>CI 2.3.3.12-1 LRA Section 2.3.3.12 indicates that the John Deere Diesel (JDD) is installed in compliance with 10 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 - NRC License 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 Regional Inspection 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 CI 2.3.3.12-1 is resolved.
>
1-10 CI 2.3.3.13a-1 The LRA states that the augmented off-gas system is within the scope of license renewal based on 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 prox imity to safety-related equipment or where a structural/seismic boundary exists. This informat ion is not provided on license renewal drawings nor was a detailed description provided in t he 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 - NRC License 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 applicant amended 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 CI 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 based on 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 equi pment and do not identify structural/seismic boundaries. Without license renewal drawings and/or detailed description of the circulating
 
water system, the omission of components s ubject 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 - NRC License 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 1-11 components, the components within the system ar e 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 applicant>stated NRC Regional Inspection Team found that if any nonsafety-related portion of a fluid
>system is located within a building containi ng 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 CI 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 in accordance 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 prox imity to safety-related equipment or where a structural/seismic boundary exists. This informat ion 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 - NRC License 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 ar e 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.
>
1-12 Based on its review, the staff found the above response acceptable because the applicant>stated NRC Regional Inspection Team found that if any nonsafety-related portion of a fluid
>system is located within a building containi ng 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 CI 2.3.3.13m-1 is resolved.
>1.7  Summary of Proposed License Conditions Following 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 by 10 CFR 54.21(d) in the next UFSAR update, as required by 10 CFR 50.71(e), following the
 
issuance of the renewed license.
The second license condition requires future activities identified in the UFSAR supplement to be completed prior to the period of extended operation.
The third license condition requires that all capsules in the reactor vessel, that are removed and tested, 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.
>
1-13>The fourth license condition requires that the licensee perform and submit to the NRC for review and approval, a ASME Code analysis for the reactor recirculation outlet nozzle and the core
 
spray nozzle at least two years prior to the period of extended operation. These analyses
 
should be documented in the FSAR as the *analysis of record* for these two nozzles.
>THIS PAGE INTENTIONALLY LEFT BLANK.
2-1 SECTION  2 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW
 
===2.1 Scoping===
and Screening Methodology
 
====2.1.1 Introduction====
Title 10, Section 54.21, of the Code of Federal Regulations (CFR), "Contents of Application Technical 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 syst ems, structures, and components (SSCs) within the scope of license renewal.
LRA Section 2.1, "Scoping and Screening Methodology," describes the methodology for identifying 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 the requirements 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 Application LRA 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" 2-2 LRA Section 3, "Aging Management Review Results," states the applicant's aging management results 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-limited aging analyses.
 
====2.1.3 Scoping====
and Screening Program Review The staff evaluated the LRA scoping and screening methodology in accordance with the guidance 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 and structures 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 applicant to identify plant SCs subject to an AMR With the guidance of the corresponding SRP-LR sections, the staff reviewed, as part of the applicant'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 within the 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 subject to 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, Vermont during 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 re viewed 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 2-3 management program (AMP) activities described in LRA Appendix A, "Updated Final Safety Analysis 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 t he 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 and Screening The staff reviewed the applicant's scoping and screening implementation procedures as documented 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 license renewal 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 plant systems 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 license renewal highlighted in color.
2.1.3.1.2  Staff Evaluation
 
Scoping and Screening Implementation Procedures. The staff reviewed the following scoping and screening methodology implementation procedures:
The staff reviewed the applicant's scoping and screening methodology implementation procedures, including license renewal project guidelines (LRPGs), license renewal project 2-4 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 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 staff found the overall process for implementing 10 CFR Part 54 requirements included in the 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 2.1 consistent 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 stated in safety classification documents, the Maintenance Rule SSC basis documents for each
 
system, and in design basis documents for system s 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 the applicant'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 CLB
 
includes NRC regulations, orders, license conditi ons, 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 enforcement
 
actions 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 such information, including the UFSAR, DBDs, controlled plant reference drawings, LRBDs, and
 
Maintenance Rule information. In addition, the applicant's license renewal process identified
 
additional 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, the
 
applicant supplemented the review by using an electronic database developed during the plant
 
FSAR accuracy verification project conducted between 1998 and 2000. The database contained 2-5 approximately 10,000 documents including all co rrespondence 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 pl ant 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 the staff 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 implementation procedures, 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.
2.1.3.2  Quality Controls Applied to LRA Development 2.1.3.2.1  Staff Evaluation The staff reviewed the quality controls used by the applicant to ensure that scoping and screening 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 written procedures.
* The applicant reviewed previous LRA NRC requests for additional information to ensure 2-6 that applicable issues were addressed in the LRA.
* The LRA was reviewed by the Offsite and Onsite Safety Review Committees prior to submittal 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. The purpose 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's license 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  Training 2.1.3.3.1  Staff Evaluation The staff reviewed the applicant's training process for consistent and appropriate guidelines and 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 renewal project and site personnel. The training consisted of a combination of reading and attending
 
training 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
 
were required to review applicable license renewal regulations, NEI 95-10 and associated
 
procedures. 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 the applicant'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 responsible 2-7 for 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 the scoping 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 and screening 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 Methodology LRA 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.
Finally, the applicant evaluated the components in the systems and structures that were in-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 described the 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 ar e 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 2-8 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 in the 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 upon to 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 (or equivalent) 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).
The staff's review of LRA Section 2.1 of VYNPS identified areas in which additional information was 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-accident DBEs, 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.
2-9 In its response, by letter dated August 10, 2006, the applicant described the DBEs evaluated during 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 were addressed 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 safe ty classification of systems and components as governed by the plant safety classification proc ess. 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 identifies
 
those 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. The staff 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 in
 
NUREG-1800.
The staff reviewed the additional information provided by the applicant and, on the basis of providing (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
 
description of the processes and sources of DBE information used to perform the scoping
 
evaluation 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 accordance with 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 Intake Structure 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 2-10 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 syst em 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 classified as 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 r enewal 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.
The staff reviewed the safety classification criteria used to determine the safety classification to verify 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 to 10 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 CLB definitions 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 construction
 
permit 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 additional
 
functions for the standby liquid control (SLC) and residual heat removal (RHR) systems: (1) the 2-11 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 the 10 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 the applicant'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's scoping 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.
2.1.4.2  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 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 the
 
SSCs that met 10 CFR 54.4(a)(2) using three categories: (1)Nonsafety-Related SSCs Required to Perform a Function that Supports a Safety-Related SSC The SSCs required to perform a function in support of safety-related components were classified 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 SSCs The applicant identified certain nonsafety-related components and piping outside of the safety-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 2-12 support function.
For piping in this structural boundary, pressure integrity is not required (except when required for 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 draw ings 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 draw ings 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. (3)Nonsafety-related SSCs with a Potential for Spatial Interaction with Safety-Related SSCs The applicant considered physical impact, and fluid leakage, spray or flooding when evaluating the potential for spatial interaction between nons afety-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 Flooding The applicant evaluated missiles which could be generated from internal or external events such as failure of rotating equipment. Inherent nonsafety-related features that protect
 
safety-related equipment from missiles; over head-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 the UFSAR and relevant topical design basis doc ument. The applicant's high-energy systems were evaluated to ensure identification of components that are part of nonsafety-related high-energy 2-13 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 Spray The applicant evaluated moderate and low energy sy stems which have the potential for spatial interactions 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-related components 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 thes e components when the environment is a dry gas. Systems containing only air or gas were not included in the scope of license renewal.
Protective 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, the failure 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 Applications to 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-rela ted 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 their evaluation on the plant's CLB, engineering judgement and analyses, and relevant operating 2-14 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 SSCs Whose 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 NRC guidance to the industry on identification and treatment of such SSCs:
Nonsafety-Related SSCs Required to Perform Functions that Support a Safety-Related SSCs Nonsafety-related SSCs required to perform a function in order to support a safety-related function 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
 
applicant's 10 CFR 54.4(a)(2) project report. The single exception to this approach was the
 
main 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 per form a function that supports a safety-related intended function.
Nonsafety-Related SSCs Connected to Safety-Related SSCs The 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 be
 
identified 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 2-15 scope of license renewal.
The staff was unable to determine whether equivalent anchors (such as a combination of supports 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 the applicant 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
 
structural boundaries, and in those instances where isometric drawings were not readily
 
available, 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 the applicant 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 SSCs The applicant considered physical impact, and fluid leakage, spray or flooding when evaluating the potential for spatial interaction between nons afety-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 where missiles 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 2-16 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-energy lines, 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 i dentified 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 included within the scope of license renewal in accordance with 10 CFR 54.4(a)(1). The
 
remaining 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 sy stems that have the potential for spatial interactions 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 to identify 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 det ermine 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 2-17 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 to RAI 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.
In addition, protective features, such as whip restraints, spray shields, supports, missile or flood barriers (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 identifying systems 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 described the 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 mechanica l systems were included in-scope of license renewal.Fire Protection. The applicant described the scoping of mechanical systems and structures required 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 2-18 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 qualification requirements of 10 CFR 50.49 in LRA Section 2.1.1.3.2, "Commission's Regulations for
 
Environmental Qualification (10 CFR 50.49)." A ll 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 Yankee is a Boiling Water Reactor.
Anticipated Transient Without Scram. The applicant described the scoping of mechanical systems 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 structures relied 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 in the 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. System s 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 ve rify that the systems performed no intended functions for license renewal regulated events.
2-19 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 i dentifies 23 mechanical systems which have one or more 10 CFR 50.48 intended functions. The report also identifies the structures that are
 
included 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 has one intended function, which is to provide support for the CO 2 tank. Environmental Qualification. For the environmental qualification regulated event, the staff reviewed 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 the mechanical 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 r od 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 and structures 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, identif ies 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 safety analyses 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 2-20 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 bei ng 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
 
methodology 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, the applicant 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. A ll additional mechanical and electrical systems associated 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 that support 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 Structures 2.1.4.4.1  Summary of Technical Information in the Application System and Structure Level Scoping. The applicant documented its methodology for performing the 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 us e CLB documents, describe the system or 2-21 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 st ructures function lists to the scoping criteria to determine whether the functions met the scoping criteria of 10 CFR 54.4(a). The applicant
 
documented 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 the scope 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 and electrical 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-sc ope electrical components subject to an AMR.
Structural components were grouped as structur al commodity types. Commodity types were based on materials of construction. LRA Section 2.1.2.2.1 identified the various structural
 
commodity groups including:
* steel 2-22
* threaded fasteners
* concrete
* fire barriers
* elastomers
* earthen structures
* flouropolymers and lubrite sliding surfaces Insulation. LRA Section 2.4.6, "Bulk Commodities," stated that insulation may have the specific intended 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 and components 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 it performed 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 electrical
 
systems 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 2-23 further screened to determine if they required an AMR. The staff did not identify any discrepancies with the methodology used by the applicant.
The 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 accordance with the LRPGs. This documentation included the de scription 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 LRPD and 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 applicant followed the process described in NUREG-1800, and appropriately identified and categorized
 
the various consumables in accordance with the guidance. Plant consumables were initially
 
identified and evaluated to determine if any met the criteria requiring an AMR, such as structural
 
sealants. Additionally, the applicant identified all pertinent industry guidelines which were 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 a sampling 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 ty pes, and commodity groups within the scope of license renewal and their intended functions.2.1.4.5  Mechanical Component Scoping 2.1.4.5.1  Summary of Technical Information in the Application In LRA Section 2.1, the applicant described the methodology for identifying mechanical system components 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 syst em 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 t hose components. Defining a system by the 2-24 components in the database is generally consistent with the VYNPS maintenance rule scoping documents and safety classification procedure.
Each mechanical system 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, safe ty 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 each system showing the in-scope components. Com ponents 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 with mechanical 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 was
 
adequately implemented.
2-25 Scoping Methodology for the Core Spray System In LRA Section 2.3.2.2, "Core Spray," the applicant provided the scoping and screening methodology results for SSCs within the CS syst em. 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 boundary The 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 sati sfactory accomplishment of a safety function The 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 CFR 50.48)
* 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 piping and 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 CS mechanical 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 i dentified 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 piping and instrumentation diagrams (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. Additi onally, 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 2-26 effort.2.1.4.5.3  Conclusion Based on its review of the LRA, scoping implementation procedures, and the system sample and 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 Scoping 2.1.4.6.1  Summary of Technical Information in the Application In LRA Section 2.1, the applicant described the methodology for identifying structures that are in 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 individual structures 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 the functions 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 of license 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
 
intended functions performed by the structure. The results of the review were documented in the 2-27 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 and reviewed 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 Scoping 2.1.4.7.1  Summary of Technical Information in the Application LRA Section 2.1.1, "Scoping Methodology" describes the scoping process associated with electrical systems and components. For the pur poses 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 LRA
 
Section 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 differ ent 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 procedures and aging management reports, as documented in the audit report, governing the electrical
 
scoping methodology. The scoping phase for electrical components began with placing all
 
electrical components from plant systems with in 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
 
from 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 2-28 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 Methodology Based on its review of the LRA and the scoping implementation procedures, the staff determines 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====
Methodology2.1.5.1  General Screening Methodology After identifying systems and structures within the scope of license renewal, the applicant implemented 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 of identifying components from in-scope systems and st ructures 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 mechanical system, structure and electrical commodity group.
Identification of the license renewal intended function(s) for all mechanical and structural component types and electrical commodity groups.
Active components were screened out and therefore, did not require an AMR. The screening process also identified short lived com ponents 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.
2.1.5.1.2  Staff Evaluation
 
Pursuant to 10 CFR 54.21, the Commission requires that each LRA must contain an IPA that identifies SCs within the scope of license renewal that are subject to an AMR. The IPA must 2-29 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 and structural component types, and electrical comm odity 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-sc ope component types and commodity groups to determine 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 each discipline and provided administrative doc umentation that described the screening methodology. Specific methodology for mechanical, electrical, and structural is discussed
 
below.2.1.5.1.3  Conclusion
 
Based on its review of the LRA, the screening implementation procedures, and a sampling of screening 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 co mmodity groups subject to an AMR meets 10 CFR 54.21 requirements and, therefore, is acceptable.2.1.5.2  Mechanical Component Screening 2.1.5.2.1  Summary of Technical Information in the Application In LRA Section 2.1.2.1, "Screening of Mechanical Systems," the applicant discussed the screening 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 system s in-scope for 10 CFR 54.4(a)(2) for physical interactions, as discussed below). In addition, the drawings identify components that are subject
 
to 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 2-30 subject to an AMR (i.e., passive, long-lived co mponents 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 of Mechanical 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 com ponents 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 pr ovide 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 further with 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 asso ciated 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 SSCs which 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.
Additionally, the staff reviewed the screening activities associated with the CS system. The staff reviewed the system intended functions and associated source documents identified for the
 
system, the CS flow diagrams, and the asso ciated 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.
2-31 2.1.5.2.3  Conclusion Based on its review of the LRA, the screening implementation procedures, and a sample review of 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 Screening 2.1.5.3.1  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 aging management (AM) reports, as described in the audit report, provided
>detailed implementation guidance 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 descri bed in separate AM reports for each system.
The staff reviewed the applicant's methodology used for structural screening described in LRA 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 2-32 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 and
 
indicated 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 fr om the implementation of this methodology by reviewing 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 identif ied 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 Screening 2.1.5.4.1  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.
The applicant determined that the majority of EIC commodity groups are active and do not require 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 2-33assemblies Additionally, the pressure boundary function that may be associated with some EIC components identified in NEI 95-10, Appendix B (flow elements, vibration probes) was considered in the
 
mechanical AMRs, as applicable. Electrical components supported by structural commodities (cable trays, conduit and cable trenches) were included in the structural AMRs.
The applicant reviewed the passive electrical components to determine those components that were 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 LRA Sections 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 passive SCs 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
 
environmental qualification master list identif ied the short-lived components included in the Environmental 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 "passive component 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.
2-34 2.1.5.4.3  Conclusion The staff reviewed the LRA, procedures, electrical drawings, and a sample of the results of the screening 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 is
 
consistent with the requirements of 10 CFR 54.21(a)(1), and is therefore acceptable.
 
2.1.5.5  Conclusion for Screening Methodology Based on its review of the LRA, the screening implementation procedures, discussions with the applicant'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 Findings The information in LRA Section 2.1, the supporting information in the scoping and screening implementation 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.
2.2  Plant-Level Scoping Results
 
====2.2.1 Introduction====
In LRA Section 2.1, the applicant described the methodology for identifying SSCs within the scope 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 Application In 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 2-35 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====
Evaluation In LRA Section 2.1, the applicant described its methodology for identifying systems and structures 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 verify
 
that 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 within the 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 stru ctures 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 to complete the review of the applicant's plant-level scoping results. The applicant responded to
 
the staff's RAIs as discussed below.
LRA Table 2.2-4, "Structures Not within the Scope of License Renewal," identifies the office building (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 called by 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 because the applicant clarified the use of the term office building; therefore, the staff's concern described
 
in RAI 2.2-1 is resolved.
2-36 The pressure regulator and TG control system is described in USFAR Section 7.11. The purpose 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 and TG control system as described in UFSAR Section 7.11 is an electrical and instrumentation and
 
control (EIC) portion of the main TG system lis ted 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. Com ponents 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-l 1 a. The pressure regulator and TG control system as described in
>UFSAR Section 7.
1 1 11 are not considered separate systems and therefore are not listed in
>LRA Table 2.2-l 1 a. 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.
Based on its review, the staff finds the applicant's response to RAI 2.2-3 acceptable because the 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 the Vermont 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 supplementary information 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:
2-37
* 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 system The above 13 mechanical systems were added to LRA Table 2.2-1a and removed from LRA Table 2.2-2.
The following mechanical systems had system boundary changes. For these systems, new component 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
* 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 system The 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 as falling within the scope of license renewal to ve rify whether the systems and structures have any intended functions that would require their inclusion within the scope of license renewal in
 
accordance with 10 CFR 54.4. The staff's review of the applicant's implementation was
 
conducted in accordance with the guidance described in SRP-LR Section 2.2, "Plant-Level
 
Scoping Results."
2-38 2.2.4  Conclusion The staff reviewed LRA Section 2.2, the RAI responses, the response to the license renewal inspection 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 Systems This 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 systems In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant's IPA 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
 
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
 
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 in
 
accordance with 10 CFR 54.21(a)(1).
In its scoping evaluation, the staff reviewed the applicable LRA sections and component drawings, 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 app licant 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. For those 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.
2-39 Two-Tier Scoping Review Process for Balance of Plant (BOP) Systems Of the 78 mechanical systems in the LRA, 44 are BOP systems which include most of the auxiliary 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 staff reviewed 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 reviews Examples of the safety important/risk significant systems are the instrument air (IA) system, the diesel generator (DG) and support systems, and the SW system, based on the results of the
 
individual plant examination for VYNPS. An exampl e of a system whose failure could result in common 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 system s 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 review as 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
 
would identify apparent missing components for an AMR. The following is a list of these 21 systems:
* 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 st eam 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 2-40
* main turbine generator
* turbine lube oil The 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 t he 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 Inspection The staff used an inspection to verify 10 CFR 54.4(a)(2) scoping results. The staff identified several 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 system As a result of the regional inspection and other staff inquiry, the applicant issued letters to the NRC 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
 
inspection. 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 System LRA Section 2.3.1 states that the purposes of the reactor coolant system (RCS) are to house the 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 boundary The staff's findings on review of LRA Sections 2.3.1.1 - 2.3.1.3 are in SER Sections 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, 2-41 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 the following 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 for adjusting 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 (RCIC) turbine operation is provided by connections to the MS piping. Class 1 feedwater lines
 
provide 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 in terfacing 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 and following 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 NB system within the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* flow element
* orifice
* piping
* tubing 2-42
* valve body The nonsafety-related NB system component intended function within the scope of license renewal is to provide a pressure boundary.
CRD System. The CRDs provide a means to control changes in core reactivity by incrementally positioning 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-relat ed 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 types within the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* orifice
* piping
* pump casing
* strainer housing
* tank
* tubing
* valve body The nonsafety-related CRD component intended function within the scope of license renewal is to provide a pressure boundary.
HCU System. The HCU system controls the water flow to the CRDs both for normal operation and 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 and following DBEs. The failure of nonsafety-related SSCs in the HCU system could prevent the
 
satisfactory accomplishment of a safety-relat ed 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 types within the scope of license renewal and subject to an AMR:
* bolting
* filter housing 2-43
* piping
* tubing
* valve body The nonsafety-related HCU system component intended function within the scope of license renewal is to provide a pressure boundary.
Staff Evaluation. The staff reviewed LRA Section 2.3.1, UFSAR Sections 3.4, 3.5, 4.1 through 4.6, 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 the applicant 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 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 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
 
required by 10 CFR 54.21(a)(1).
2.3.1.1  Reactor Vessel 2.3.1.1.1  Summary of Technical Information in the Application LRA Section 2.3.1.1 describes the reactor vessel, which contains the nuclear fuel core, core support 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 of license renewal and subject to an AMR:
* bolting
* heads and shell
* nozzles and penetrations
* safe ends, thermal sleeves, flanges, and caps
* vessel attachments and supports The reactor vessel component intended functions within the scope of license renewal include the following:
2-44
* pressure boundary
* structural or functional support for safety-related equipment 2.3.1.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.1 and the UFSAR using the 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
 
applicant has identified as within the scope of license renewal to verify that the applicant has not
 
omitted any passive and long-lived component s 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 a component 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 included within the scope of license renewal 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 2.3.1.1-1 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 scram discharge 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 were included 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 CRD housing 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 were considered 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.
2-45 2.3.1.1.3  Conclusion The staff reviewed the LRA 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 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 Internals 2.3.1.2.1  Summary of Technical Information in the Application LRA Section 2.3.1.2 describes the reactor vessel internals, which are designed to distribute the reactor 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
 
pump instrumentation, shroud (including shroud stabilizers), shroud head and steam separator
 
assembly, 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 the scope 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 guide The reactor vessel internals component intended functions within the scope of license renewal include the following:
* flow distribution
* boundary of a volume in which the core can be flooded and adequately cooled in the event of a breach in the nuclear system process barrier external to the reactor vessel
* pressure boundary 2-46
* structural or functional support for safety-related equipment
* structural integrity so loose parts are not introduced 2.3.1.2.2  Staff Evaluation The staff reviewed LRA Section 2.3.1.2 and the UFSAR using the 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
 
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
 
The staff reviewed the LRA 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 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 Boundary 2.3.1.3.1  Summary of Technical Information in the Application LRA Section 2.3.1.3 describes the RCPB, which maintains a high-integrity pressure boundary and 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 license renewal 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) 2-47
* 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 NPS The RCPB component intended functions within the scope of license renewal include the following:
* flow control
* pressure boundary 2.3.1.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.3 and the UFSAR using the 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
 
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 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 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).
2-482.3.2  Engineered Safety Features In LRA Section 2.3.2, the applicant identified the SCs of the engineered safety features that are subject to an AMR for license renewal.
The applicant described the supporting SCs of the engineered safety features in the following LRA 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 penetrations The staff's review findings regarding LRA Sections 2.3.2.1 - 2.3.2.7 are presented in SER Sections 2.3.2.1 - 2.3.2.7, respectively.
2.3.2.1  Residual Heat Removal 2.3.2.1.1  Summary of Technical Information in the Application LRA Section 2.3.2.1 describes the RHR system , which removes decay heat energy from the reactor 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.
2-49 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 coo ling 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 and following 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 within the scope of license renewal and subject to an AMR:
* bolting
* cyclone separator
* heat exchanger (bonnet)
* heat exchanger (shell)
* heat exchanger (tubes)
* nozzle
* orifice
* piping
* pump casing
* strainer
* tank
* thermowell
* tubing
* valve body The RHR system component intended functions within the scope of license renewal include the following:
* flow control
* filtration
* heat transfer
* pressure boundary 2.3.2.1.2  Staff Evaluation
 
The staff reviewed LRA Sections 2.3.2.1 and 2.3.3.13, and UFSAR Sections 4.8 and 6.4.4 using the 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 2-50 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 have LPCI 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 vortex breakers are employed in the emergency core cooling system (ECCS) pump suction lines at VYNPS, 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 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 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 Spray 2.3.2.2.1  Summary of Technical Information in the Application LRA Section 2.3.2.2 describes the CS system, which in conjunction with other CSCS, provides adequate 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 c entrifugal 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.
2-51 The CS system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-relat ed SSCs in the CS system potentially could prevent the satisfactory accomplishment of a sa fety-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 within the scope of license renewal and subject to an AMR:
* bolting
* bearing housing
* cyclone separator
* flow nozzle
* orifice
* piping
* pump casing
* strainer
* tubing
* valve body The CS system component intended functions within the scope of license renewal include the following:
* flow control
* filtration
* pressure boundary
 
2.3.2.2.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.2 and UFSAR Sections 6.3 and 6.4.3 using the 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
 
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 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 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 Depressurization 2.3.2.3.1  Summary of Technical Information in the Application 2-52 LRA Section 2.3.2.3 describes the automatic depressurization system (ADS), which actuates nuclear system pressure relief valves to depre ssurize 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 following DBEs. 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.
LRA Table 2.3.2-3 identifies the following ADS component types within the scope of license renewal and subject to an AMR:
* bolting
* orifice
* piping
* tubing
* valve body The ADS component intended functions within the scope of license renewal include the following:
* flow control
* pressure boundary 2.3.2.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.3 and UFSAR Sections 4.4 and 6.4.2 using the 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
 
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 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 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 Injection 2-53 2.3.2.4.1  Summary of Technical Information in the Application LRA Section 2.3.2.4 describes the HPCI system, which cools the reactor core adequately in a small 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.
The HPCI system has safety-related components relied upon to remain functional during and following 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 within the 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 body The HPCI system component intended functions within the scope of license renewal include the following:
* flow control
* filtration
* heat transfer
* pressure boundary 2-54 2.3.2.4.2  Staff Evaluation The staff reviewed LRA Sections 2.3.2.4 and 2.3.3.13, and UFSAR Sections 6.3 and 6.4 using the 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
 
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).
2.3.2.4.3  Conclusion
 
The staff reviewed the LRA 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 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 Cooling 2.3.2.5.1  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 ma ke 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 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. 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 systems component types within the scope of license renewal and subject to an AMR:
* bolting
* condenser 2-55
* drain pot
* filter housing
* flow indicator
* heat exchanger (bonnet)
* heat exchanger (shell)
* heat exchanger (tubes)
* orifice
* piping
* pump casing
* rupture disk
* sight glass
* steam heater
* steam trap
* strainer
* strainer housing
* tank
* thermowell
* tubing
* turbine casing
* valve body The component intended functions within the scope of license renewal include the following:
* flow control
* filtration
* heat transfer
* pressure boundary 2.3.2.5.2  Staff Evaluation
 
The staff reviewed LRA Sections 2.3.2.5 and 2.3.3.13, and UFSAR Sections 4.7 and 11.8.3.8 using the 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
 
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 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 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).
2-56 2.3.2.6  Standby Gas Treatment 2.3.2.6.1  Summary of Technical Information in the Application LRA Section 2.3.2.6 describes the standby gas treatment (SBGT) system, which processes gaseous effluent from the primary and secondary containments when required to limit the
 
discharge of radioactive materials to the environs and to limit ex-filtration from the secondary
 
containment during primary containment isolat ion. 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 and following DBEs. The failure of nonsafety-relat ed 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 types within 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 body The SBGT system component intended functions within the scope of license renewal include the following:
* filtration
* pressure boundary 2.3.2.6.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.6 and UFSAR Sections 1.6.2.15 and 5.3.4 using the 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 2-57 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).
2.3.2.6.3  Conclusion
 
The staff reviewed the LRA 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 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 Penetrations 2.3.2.7.1  Summary of Technical Information in the Application LRA Section 2.3.2.7 describes the primary containment penetrations, which can rapidly isolate all 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 remain functional during and following DBEs.
LRA Table 2.3.2-7 identifies the following primary containment penetrations component types within the scope of license renewal and subject to an AMR:
* bolting
* piping
* valve body The intended function of the primary containment penetrations is to provide a pressure boundary.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 using the 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
 
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).
2-58 2.3.2.7.3  Conclusion The staff reviewed the LRA 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 primary containment penetrations 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  Auxiliary Systems
>In LRA Section 2.3.3, the applicant identified the SCs of the auxiliary systems subject to an AMR for license renewal.
The applicant described the supporting SCs of t he 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 atmosphere dilution
* 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 SER Sections 2.3.3.1 - 2.3.3.13, respectively.
2.3.3.1  Standby Liquid Control 2.3.3.1.1  Summary of Technical Information in the Application LRA Section 2.3.3.1 describes the SLC system, which, independent of the control rods, shuts down 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 2-59 reactivity effects of a colder moderator. The system , located in the reactor building, consists of a boron solution tank, a test water tank, two posit ive-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.
The SLC system has safety-related components relied upon to remain functional during and
 
following 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 within the scope of license renewal and subject to an AMR:
* bolting
* gauge
* heater
* orifice
* piping
* pump casing
* sight glass
* strainer housing
* tank
* thermowell
* tubing
* valve body The SLC system component intended function within the scope of license renewal is to provide a 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 the 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
 
applicant has identified as within the scope of license renewal to verify that the applicant has not
 
omitted any passive and long-lived component s 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 SSCs within 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 2-60 required by 10 CFR 54.21(a)(1).
2.3.3.2  Service Water 2.3.3.2.1  Summary of Technical Information in the Application LRA Section 2.3.3.2 describes the SW system and the RHRSW system. The purpose of the SW 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 t he 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 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. 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 RHRSW system 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 2-61 The 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 equipment 2.3.3.2.2  Staff Evaluation
 
The staff reviewed LRA Sections 2.3.3.2 and 2.3.3.13, and UFSAR Sections 10.6, 10.7, and 10.8 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 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).
The staff's review of LRA Section 2.3.3.2 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
The staff noted that license renewal drawing LRA-G-191159-SH-01-0, at location H-12, depicts pipe 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-566C contains 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 acceptable because 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, drawing note 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 shown within the scope of license renewal. Failure of this pipe could have an adverse effect on 2-62 the 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 is included 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 acceptable because 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 the license 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 only show the portions of the system with int ended 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 va lves 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
 
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 2-63 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 acceptable because 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 a license 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 only show the portions of the system with int ended 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-re lated, 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 applicant acknowledged that pipe 2" SW-566D is within the scope of license renewal and subject to an
 
AMR based on the potential for physical interacti on 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.
The staff's review of LRA Section 2.3.3.2 identified areas in which information provided in the LRA needed to be confirmed by the NRC Regional Inspection Team to complete the review of
 
the applicant's scoping and screening results.
2-64 Inspection Item 2.3.3.2a-1 License renewal drawing LRA-G-191159-SH-01-0, at location H-11, depicts pipe section 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).
The staff
>identified this as confirmatory item 2.3.3.2a-1.
>In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License 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 inspection team 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 I confirmatory i tem 2.3.3.2a-1 is resolved.
>Inspection Item 2.3.3.2a-2 LRA Section 2.1.2.1.2 states in part that 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. 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 , a drain line).
The staff cannot determine whether all the nonsafety-related piping systems were included up to 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).
The staff>identified this as confirmatory item 2.3.3.2a-2.
>In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License 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 2-65 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 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 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 finds the above response acceptable because the applicant>stated that NRC Regional Inspection Team found 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 10 CFR 54.4(a)(2). Furthermore,>the staff again reviewed the applicable LRA drawings for component types that may have been
 
omitted from Table 2.3.3-13-42 and found all component types have been added to LRA
>Table 2.3.3-13-42 in Table 2.3.3-13-42 to be consistent with the component types included
>within the scope of license renewal at similar facilities. Therefore, the staff concern described in
>Inspection I confirmatory i tem 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
>inspection confirmatory item 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).
2.3.3.3  Reactor Building Closed Cooling Water 2.3.3.3.1  Summary of Technical Information in the Application LRA Section 2.3.3.3 describes the RBCCW system, which supplies demineralized water to the 2-66 reactor building auxiliary equipment systems fr om a closed cooling loop. The RBCCW system cools equipment which may contain radioactive fluids. The SW system provides the heat sink
 
for 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 during and 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 types within 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 body The RBCCW system component intended functions within the scope of license renewal include the following:
* pressure boundary
* structural or functional support for safety-related equipment 2.3.3.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.3 and UFSAR Section 10.9 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 and UFSAR to verify that the applicant has not omitted from the scope of license renewal any 2-67 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 was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
The staff noted that license renewal drawing LRA-G-191159-SH-03-0, at location P-10 at valve 29 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 the ACS 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 acceptable because 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, LR A-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 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
 
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).
2.3.3.4  Emergency Diesel Generator 2.3.3.4.1  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 of the DG system is to provide Class 1E electr ical 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 2-68 in the DG system.
The DG and DLO systems have safety-related components relied upon to remain 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. 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 and auxiliaries system, and DLO system component ty pes 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 The component intended functions within the scope of license renewal include the following:
* flow control
* filtration
* heat transfer
* pressure boundary 2.3.3.4.2  Staff Evaluation
 
The staff reviewed LRA Sections 2.3.3.4 and 2.3.3.13, and UFSAR Section 8.5 using the Tier-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 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 2-69 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 the deletion 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 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
 
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 Cooling 2.3.3.5.1  Summary of Technical Information in the Application LRA Section 2.3.3.5 describes the FPC system, the safety-related SBFPC subsystem, the fuel pool 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
 
the FPFD is to maintain the purity of the spent fuel pool water by minimizing corrosion product
 
buildup 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-relat ed components relied upon to remain functional during 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) 2-70
* neutron absorber (boral)
* orifice
* piping
* pump casing
* thermowell
* tubing
* valve body The component intended functions within the scope of license renewal include the following:
* heat transfer
* neutron absorption
* pressure boundary 2.3.3.5.2  Staff Evaluation
 
The staff reviewed LRA Sections 2.3.3.5 and 2.3.3.13, and UFSAR Sections 10.3 and 10.5 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 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).
The staff's review of LRA Section 2.3.3.5 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
The staff noted that license renewal drawing G-191173, Sheet 1, at location H-5 shows a section 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 drawings only 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 2-71 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 acceptable because 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.2.3.3.5.3  Conclusion
 
The staff reviewed the LRA, accompanying license renewal drawings, and RAI response 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
 
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 Oil
>2.3.3.6.1  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 well as 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 and following DBEs. The failure of nonsafety-relat ed SSCs in the FO system potentially could prevent the satisfactory accomplishment of a sa fety-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 t he following FO system component types within the scope of license renewal and subject to an AMR:
* bolting 2-72
* filter housing
* flame arrestor
* flex hose
* injector housing
* piping
* pump casing
* sight glass
* strainer housing
* tank
* thermowell
* tubing
* valve body
* strainer housing The FO system component intended functions within the scope of license renewal include the following:
* flow control
* pressure boundary 2.3.3.6.2  Staff Evaluation
 
The staff reviewed LRA Sections 2.3.3.6 and 2.3.3.13, and UFSAR Section 8.5.4 using 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 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).
The staff's review of LRA Section 2.3.3.6 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
The staff noted that license renewal drawing LRA-G-191162, Sheet 2, provides information about the EDGs, diesel-driven fire pump, and hous e HB systems, support ed 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 descr ibe the JDD system. The staff also requested that the applicant explain the relationship between the JDD and the FO systems and clarify what 2-73 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 fire pump 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 pum ped 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 to
 
an AMR. A dedicated 550-gallon fiberglass underground storage tank provides fuel to the JDD
 
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 acceptable because 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 the scope 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 verifi ed 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 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
 
FO system components within the scope of lic ense 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 Air 2.3.3.7.1  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 cont rols through a dual header system. The IA system 2-74 includes the containment N 2 supply described in the UFSAR as a separate N 2 subsystem also known as containment air. The purpose of containment N 2 is to provide pneumatically-operated components in the drywell with N 2 when the primary containment is inerted so any component leakage will not dilute the N 2 atmosphere. This N 2 source can be from either the N 2 system (normal supply) or the containment air compressor (automatic backup supply). When neither N 2 supply is available or when the containment is not inerted, IA may be lined up manually as a
 
secondary backup for the containment N
: 2. When the containment is not inerted, IA will be lined up as the primary source of pneumatic pressure.
The purpose of the SA system is to provide the station with the compressed air requirements for pneumatic instruments and controls and general st ation 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 atmospheric control (PCAC) system to satisfy the primary c ontainment purge and normal make-up requirements.
The IA, SA, 105, and N 2 systems have safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the IA and N 2 system 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 body The IA, SA and N 2 system component intended function within the scope of license renewal is to 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 the Tier-2 evaluation methodology, for IA and N 2 , and the Tier-1 methodology, for SA and 105 systems, 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).
2-75 In letters to the NRC dated July 30, 2007 and August 16, 2007, the applicant reported the deletion 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.
2.3.3.7.3  Conclusion
 
The staff reviewed the LRA and accompanying license renewal drawings 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 IA and N 2 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).
2.3.3.8  Fire Protection-Water 2.3.3.8.1  Summary of Technical Information in the Application LRA Section 2.3.3.8 describes the fire protection-water system. The fire protection system provides 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 tu rbine-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 fi re 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 could prevent 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 system component 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 2-76
* piping
* pump casing
* silencer
* strainer
* strainer housing
* tank
* tubing
* turbocharger
* valve body In 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 license renewal include the following:
* flow control
* filtration
* heat transfer
* pressure boundary 2.3.3.8.2  Staff Evaluation
 
The staff reviewed LRA Sections 2.3.3.8 and 2.3.3.13, and UFSAR Section 10.11 using the 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
 
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, and supplemental SERs listed in the VYNPS Facility Operating License C c ondition 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 information necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
In RAI 2.3.3.8-1, dated August 15, 2006, the staff stated that LRA drawing LRA-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 2-77 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.
In 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 by 10 CFR 54.4(a)(1).
The fire protection-water system intended functions as required by 10 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 by 10 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 intended function 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 LRA Section 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 2-78 scope of SSCs required for compliance with 10 CFR 50.48 and 10 CFR 50 Appendix A, GDC 3, goes beyond preserving the ability to maintain safe-shutdown in the event of a fire. The staff
 
stated 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-scope and subject to an AMR. The hydrants are identif ied 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 acceptable because 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.
2-79 Based on its review, the staff found the applicant's response to RAI 2.3.3.8-2 acceptable because 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 t he 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, dated January 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 and are 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 acceptable because 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 VYNPS fire protection safety
>evaluation Section 4.3.1(f) discusses a manually-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 sy stem 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 hose stations and deluge systems, a foam fire protection agent is available that can be
 
used to combat fires at the FO storage tank, turbine lube oil storage tank, main 2-80 and auxiliary transformers, house HBs, and the emergency diesel generators.
The turbine building foam tank (TK76-1A) and associated piping and valves are in-scope and subject 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 sy stem 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, and therefore are not subject to an AMR.
Based on its review, the staff found the applicant's response to RAI 2.3.3.8-4 acceptable because 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 and associated 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 periodi cally 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 ar e 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 VYNPS fire protection safety
>evaluation Section 4.5 discusses floor drains 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 the floor 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 VYNPS fire protection safety evaluation 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 radioactive waste system, which is in the scope for license 2-81 renewal and subject to an AMR, the staff 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 VYNPS fire
>protection safety evaluation 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 potential fire 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 re circulation pump oil collection system.
As shown on LRA drawing LRA-G-191163-SH-01-0, "Fire Protection System Inner Loop," hose stations 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 acceptable because VYNPS is a BWR with an inert containment atmosphere and the primary containment
 
does not have a fixed suppression system or a r eactor 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 collect ion 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 VYNPS fire
>protection safety evaluation 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.
In 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 as the 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.
2-82 Based on its review, the staff found the applicant's response to RAI 2.3.3.8-7 acceptable because 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 VYNPS fire protection safety
>evaluation Section 4.3.1(e) discusses the automatic 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 of license 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 protection subsystems 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 main transformer 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 transfo rmer sprinkler systems are addressed in the
>SE VYNPS fire protection safety evaluation , 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 containing 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 VYNPS fire protection safety
>
2-83 evaluation Section 5.12.6 discusses the use 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 notified the 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. The
>SE VYNPS fire protection safety evaluation 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 excludes several types of fire protection components that appear in the SE VYNPS fire protection safety
>evaluation 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
* restricting orifices
* interface flanges
* chamber housings
* heat-actuated devices
* gauge snubbers
* tank heaters
* thermowells
* water motor alarms 2-84
* 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 in Table 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, hose stations 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" line item in LRA Table 2.3.3-8.
* hose racks - Since they support criterion (a)(3) equipment, hose racks are 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" in component 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, piping supports 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 2.3.3-8.
* 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 2.3.3-8.
* flexible hoses - Hoses are replaced on a specified periodicity and therefore, are not subject to an AMR as required by
 
10 CFR 54.21(a)(1)(ii).
2-85
* restricting orifices - 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. 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" in component 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, the pre-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 that protect 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 UFSAR discuss 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" in component lists may include pipe, pipe fittings (such as elbows and
 
reducers), flow elements, orifices, and thermowells. Thermowells are
 
included in the "Piping" line item in LRA Table 2.3.3-8.
* water motor alarms - This response assumes that reviewer means water flow alarms which are provided in critical locations and annunciate in the
 
control room to provide positive indi cation of fire water system operation.
Water flow alarms are active components; not subject to an AMR.
2-86
* fire hydrants (casing) - As described in response to RAI 2.3.3.8-1, the yard 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" line item in LRA Table 2.3.3-8.
* dikes (contain oil spill) - Dikes are included in the structural AMR. They are included in the "Flood curb" line items in LRA Table 2.4-6.
* flame retardant coating for cables - As described in response to RAI 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 included in 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 are included 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 tank for 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.
* fire retardant coating for structural steel supporting wall and ceiling - As described 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. Flamemas tic 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 t he 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, 2-87 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 appropr iately 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: flexib le 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 component s 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 flow nozzles (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 acceptable because 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 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 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).
2.3.3.9  Fire Protection-Carbon Dioxide 2.3.3.9.1  Summary of Technical Information in the Application LRA Section 2.3.3.9 describes the fire protection-CO 2 system. The purpose of the fire protection system is to provide 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. The cable vault and switchgear rooms are protected by fully automatic total flooding CO 2 suppression 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 initiated by heat detectors. The automatic total flooding high-pressure CO 2 gas suppression systems for the cable vault and 2-88 diesel fire pump FO storage tank room store high-pressure CO 2 at ambient temperatures in steel CO 2 tanks. Empty fixed piping systems convey CO 2 from the tanks to open 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 room for 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 at approximately 0 F in an outside storage tank. Empty fixed piping systems convey CO 2 from the storage 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 within the 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 body In 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 license renewal include the following:
* flow control
* filtration
* pressure boundary 2.3.3.9.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.9 and UFSAR Section 10.11 using the 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
 
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).
2-89 The staff also reviewed the approved fire protection SER, dated January 13, 1978, approving the VYNPS fire protection program and supplemental SERs listed in the VYNPS Facility>Operating License C c ondition 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 information necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
In RAI 2.3.3.9-1, dated August 15, 2006, the staff stated that SE VYNPS fire protection safety
>evaluation Sections 3.1.5 and 4.3.2 discuss a total flooding CO 2 system for the cable spreading
>area, battery room, and diesel driven fire wa ter pump tank room. The LRA does not list the CO 2 system for the cable spreading 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 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 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 are protected by fully automatic total flooding CO 2 suppression systems initiated by ionization 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 suppression system initiated by heat detectors.
As further described in LRA Section 2.3.3.9, the fire protection-CO 2 system is within the scope of license renewal and has the following intended function as
 
required by 10 CFR 54.4(a)(3).
* 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 and battery room. Therefore, the CO 2 systems for the cable spreading area, battery room, 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 acceptable because the total flooding CO 2 systems for the cable spreading area, battery room, and diesel driven 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 VYNPS fire protection safety evaluation as the cable spreading area and battery room.
>
2-90 Therefore, the staff concludes that the total flooding CO 2 systems for the cable spreading area, battery room, and diesel driven fire water pum p 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 VYNPS fire
>protection safety evaluation and its supplements 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, the staff 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
 
included in the "Piping" line item in LRA Table 2.3.3-9.
* pipe supports - Since they support criterion (a)(3) equipment, piping supports 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.
2-91
* 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 release stations 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 storage cylinders, 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 is assured 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 these components as active or short-lived components, wh ich will result in more vigorous oversight of the condition and performance of the components. Because the applicant has interpreted 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 2.3.3.9-2 is resolved.
In RAI 2.3.3.9-3, dated August 15, 2006, the staff stated that LRA Table 2.3.3-9 listed nozzles with 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 on drawings 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 2-92 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 acceptable because 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 system does 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 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 fire protection-CO 2 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).
2.3.3.10  Heating, Ventilation, and Air Conditioning 2.3.3.10.1  Summary of Technical Information in the Application LRA Section 2.3.3.10 describes the heating, ventilation, and air conditioning (HVAC) and the house 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
 
main control room, (6) service building ventilati on provides filtration, controls temperature and humidity, 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 fo r 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.
2-93 The HVAC and HB systems have safety-relat ed components relied upon to remain functional during and following DBEs. The failure of nonsafety-related systems SSCs potentially could
 
prevent the satisfactory accomplishment of a sa fety-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 system component 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 The HVAC and HB system component intended functions within the scope of license renewal include the following:
* filtration
* heat transfer
* pressure boundary 2.3.3.10.2  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 10.12 using the 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
 
applicant has identified as within the scope of license renewal to verify that the applicant has not 2-94 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 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 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 Dilution 2.3.3.11.1  Summary of Technical Information in the Application LRA Section 2.3.3.11 describes the PCAC syst em, 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. The PCAC 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 oxy gen 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 hav e safety-related components relied upon to remain 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.
LRA Tables 2.3.3-11, 2.3.3-13-3, 2.3.3-13-27, and 2.3.3-13-28 identify the following PCAC system, 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 body 2-95 The component intended functions within the scope of license renewal include the following:
* flow control
* heat transfer
* pressure boundary 2.3.3.11.2  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 10.20 using the 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 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).
The staff's review of LRA Section 2.3.3.11 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
In RAI 2.3.3.11-1 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 a section 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.
 
In its response dated September 20, 2006, the applicant stated that the section of pipe shown on 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 X209D through 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 acceptable because the applicant confirmed that containment atmosphere dilution system piping 1"-VG-122-D1 connecting the H 2 O 2 analyzers to the torus through penetration X-209D is within the scope of license renewal and subject to an AMR. Therefore, the staff concern described in RAI 2.3.3.11-1 is resolved.
In RAI 2.3.3.11-2 dated August 16, 2006, the staff stated that license renewal drawing LRA-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 2-96 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 shown on 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 acceptable because the applicant confirmed that containment atmosphere dilution system piping from primary containment and atmosphere control sy stem 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 drawing LRA-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 drawing LRA-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
 
discrepancy on license renewal drawing LRA-VY-E-75-002-0. The piping to VG-77 is connected
 
to 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 s pace 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 cont ainment 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 identifi ed 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 drawing LRA-VY-E-75-002-0, at location J-18 shows a pi pe 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 drawing LRA-VY-E-75-002-0 shows hydrogen/oxygen analyzer panel SII within a dotted rectangular box 2-97 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 acceptable because the applicant adequately identified the piping and components in the H 2 O 2 analyzer SAH-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 SII on drawing LRA-VY-E-75-002-0. Therefore, the staff concern described in RAI 2.3.3.11-4 is resolved.In RAI 2.3.3.11-5 dated August 16, 2006, the staff stated that license renewal drawing LRA-VY-191165-0, at location I-15 provides a continuation of a pipe section from the H 2 0 2 analyzers 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.
Based on its review, the staff found the applicant response to RAI 2.3.3.11-5 acceptable because 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 s pace 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 drawing LRA-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 from the 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 2-98 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 i dentifies 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 pum p 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 acceptable because 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.2.3.3.11.3  Conclusion
 
The staff reviewed the LRA accompanying license renewal drawings, and RAI 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
 
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 Diesel 2.3.3.12.1  Summary of Technical Information in the Application LRA Section 2.3.3.12 describes the JDD as a nonsafety-related skid-mounted engine powering a 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 license renewal and subject to an AMR:
* bolting
* expansion joint
* filter housing
* heat exchanger (radiator) 2-99
* heat exchanger (shell)
* heat exchanger (tubes)
* heater housing
* piping
* pump casing
* silencer
* tubing
* turbocharger The JDD component intended functions within the scope of license renewal include the following:
* heat transfer
* pressure boundary 2.3.3.12.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.12 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 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 2.3.3.12 identified areas in which information provided in the 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 2.3.3.12-1 LRA Section 2.3.3.12 indicts that the John Deere Diesel is installed in compliance with 10 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).
The staff identified this as
>confirmatory item 2.3.3.12-1.
>In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License 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."
2-100 Based on its review, the staff found the above response acceptable because the NRC Regional Inspection 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 I confirmatory i tem 2.3.3.12-1 is resolved.
>2.3.3.12.3  Conclusion
 
The staff reviewed the LRA and Inspection I confirmatory i tem response 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 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).2.3.3.13  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 renewal requirements 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 physica l 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 could impact a safety function were identified only for systems with components supporting the main
 
condenser and MSIV leakage pathway. Two of t hese 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-gas 2.3.3.13A.1  Summary of Technical Information in the Application The AOG system collects, processes, and discharges radioactive gaseous wastes to the atmosphere 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 satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3.13-1 identifies the following AOG system component types within the scope of license renewal and subject to an AMR:
2-101
* bolting
* filter housing
* piping
* stream trap
* tank
* tubing
* valve body The AOG system component intended function within the scope of license renewal is to provide a pressure boundary.
 
2.3.3.13A.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13.1 and UFSAR Section 9.4 using the Tier-2 evaluation methodology 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 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).
The staff's review of LRA Section 2.3.3.13.1 identified areas in which information provided in the 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-1 The LRA states that the AOG system is within the scope of license renewal based on 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 prox imity to safety-related equipment or where a structural/seismic boundary exists. This informat ion 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.
The staff identified this as
>confirmatory item 2.3.3.13a-1.
>In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License 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 2-102 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 applicant amended 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 I confirmatory i tem 2.3.3.13a-1 is resolved.
>2.3.3.13A.3  Conclusion
 
The staff reviewed the LRA, accompanying license renewal drawings, and
>inspection confirmatory item response 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 Sampling 2.3.3.13B.1  Summary of Technical Information in the Application The sampling system provides means for sampling and testing various process fluids in the station 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 satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3.13-41 identifies the following sampling system component types within the scope of license renewal and subject to an AMR:
* bolting
* piping
* stainer housing
* tubing
* valve body The sampling system component intended function within the scope of license renewal is to provide 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-2 evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LR
 
Section 2.3.
2-103 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).
2.3.3.13B.3  Conclusion
 
The staff reviewed the LRA and accompanying license renewal drawings 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 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 sy stems, other systems with components supporting 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 for physical 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 cooling A description of each system above follows.
2.3.3.13C Condensate Demineralizer 2.3.3.13C.1  Summary of Technical Information in the Application The condensate demineralizer (CD) system maintains the required purity of feedwater supplied to 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 2-104 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 t he CD system potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-4 identifies the following CD system component types within the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* piping
* pump casing
* strainer housing
* tank
* tubing
* valve body The CD system component intended function within the scope of license renewal is to provide pressure 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 evaluation methodology 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 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).
2.3.3.13C.3  Conclusion
 
The staff reviewed the LRA 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 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 Demineralizer 2.3.3.13D.1  Summary of Technical Information in the Application The RWCU filter demineralizer (CUFD) system filters and cleans reactor water. The CUFD is the filter-demineralizer portion of the RWCU system and consists of the filter/demineralizer
 
tanks, piping, and valves.
2-105 The failure of nonsafety-related SSCs in the CUFD system potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-8 identifies the following CUFD system component types within the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* orifice
* piping
* pump casing
* sight glass
* strainer housing
* tank
* tubing
* valve body The CUFD system component intended function within the scope of license renewal is to provide 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 evaluation methodology 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 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).
2.3.3.13D.3  Conclusion
 
The staff reviewed the LRA 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 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 Water 2.3.3.13E.1  Summary of Technical Information in the Application The circulating water (CW) system is a heat sink for steam condensation for the main condensers. 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 2-106 racks and traveling water screens protect the circulating water pumps from debris. During cold weather, 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 and following 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 of license renewal and subject to an AMR:
* bolting
* expansion joint
* piping
* pump casing
* tank
* tubing
* valve body The CW system component intended function within the scope of license renewal is to provide pressure 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 the Tier-2 evaluation methodology described in SER Section 2.3. and the guidance described in
 
SRP-LR Section 2.3.
In conducting its review, the 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).
The staff's review of LRA Section 2.3.3.13 identified areas in which information provided in the 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 2.3.3.13e-1 The LRA states that the circulating water system is within the scope of license renewal based on 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 equi pment and do not identify structural/seismic 2-107 boundaries. Without license renewal drawings and/or detailed description of the circulating water system, the omission of components s ubject 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.
The staff identified this as confirmatory item 2.3.3.13e-1.
>In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License 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 ar e 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 applicant>stated NRC Regional Inspection Team found that if any nonsafety-related portion of a fluid
>system is located within a building containi ng 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 I confirmatory i tem>2.3.3.13e-1 is resolved.
2.3.3.13E.3  Conclusion
 
The staff reviewed the LRA and the inspection confirmatory item response 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 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 Water 2.3.3.13F.1  Summary of Technical Information in the Application The demineralized water (DW) system provides treated makeup water for such plant components as the condensate storage tank, spent fuel pool, RBCCW, and turbine building
 
closed cooling water systems. This supply function is not a safety function. The DW system 2-108 consists 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 the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-12 identifies the following DW system component types within the scope of license renewal and subject to an AMR:
* bolting
* orifice
* piping
* pump casing
* tank
* tubing
* valve body The DW system component intended function within the scope of license renewal is to provide pressure 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-2 evaluation methodology 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 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).
2.3.3.13F.3  Conclusion
 
The staff reviewed the LRA 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 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).
2-109 2.3.3.13G Feedwater 2.3.3.13G.1  Summary of Technical Information in the Application The feedwater (FW) system provides deminera lized water from the condensate system to the reactor 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 the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-13 identifies the following FW system component types within the scope of license renewal and subject to an AMR:
* bolting
* heat exchanger (shell)
* orifice
* piping
* pump casing
* strainer housing
* tubing
* valve body The FW system component intended function within the scope of license renewal is to provide pressure 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 evaluation methodology 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 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).
2.3.3.13G.3  Conclusion
 
The staff reviewed the LRA 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 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).2.3.3.13H MG Lube Oil 2.3.3.13H.1  Summary of Technical Information in the Application 2-110 The MGLO system lubricates the reactor reci rculation pump motor generator set during its operation. 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 the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-23 identifies the following MG LO system component types within the scope of license renewal and subject to an AMR:
* bolting
* heat exchanger (shell)
* piping
* pump casing
* tubing
* valve body The MGLO system component intended function wi thin the scope of license renewal is to provide 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 evaluation methodology 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 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).
2.3.3.13H.3  Conclusion
 
The staff reviewed the LRA 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 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).2.3.3.13I Neutron Monitoring 2.3.3.13I.1  Summary of Technical Information in the Application The neutron monitoring (NM) system indicates neutron flux, which can be correlated to thermal power 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 2-111 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 prov ide 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 and following DBEs. The failure of nonsafety-relat ed 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 of license renewal and subject to an AMR:
* piping
* tubing
* valve body The NM system component intended function within the scope of license renewal is to provide pressure 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 7.5 using the evaluation methodology described in SER Section 2.3. The staff conducted its review
 
in accordance with the guidance described in SRP-LR Section 2.3.
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).
2.3.3.13I.3  Conclusion
 
The staff reviewed the LRA 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 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 Water 2.3.3.13J.1  Summary of Technical Information in the Application The potable water (PW) system supplies treated water suitable for drinking and for sanitary purposes to lavatories, service sinks, combination emergency showers and eyewashes, kitchen
 
sinks, bench sinks, showers, and wall hydrants.
2-112 The failure of nonsafety-related SSCs in the PW system potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-29 identifies the following PW system component types within the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* piping
* strainer housing
* tank
* valve body The PW system component intended function within the scope of license renewal is to provide pressure 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-1 evaluation methodology 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 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).
2.3.3.13J.3  Conclusion
 
The staff reviewed the LRA 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 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 Solid 2.3.3.13K.1  Summary of Technical Information in the Application The purpose of the liquid radwaste (RDW) system is to collect potentially radioactive liquid wastes, 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 dis posal. 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 2-113 the RHR system maintains the RHR system pressure boundary.
The RDW system has safety-related components relied upon to remain functional during and following 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 scope of license renewal and subject to an AMR:
* bolting
* orifice
* piping
* pump casing
* strainer housing
* tank
* tubing
* valve body The RDW system component intended function within the scope of license renewal is to provide pressure 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-2 evaluation methodology 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 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).
2.3.3.13K.3  Conclusion
 
The staff reviewed the LRA 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 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 Place 2.3.3.13L.1  Summary of Technical Information in the Application This system designation in the component database is for obsolete equipment. It has no safety-related components and no system int ended functions; however, certain components supporting safety-related components are required to maintain structural integrity.
2-114 The failure of nonsafety-related SSCs of equipment retired in place (RIP) potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-35 identifies the following component types of equipment RIP within the scope of license renewal and subject to an AMR:
* bolting
* piping
* valve body The equipment RIP component intended function within the scope of license renewal is to provide 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 described in 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 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).
2.3.3.13L.3  Conclusion
 
The staff reviewed the LRA 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 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-Up 2.3.3.13M.1  Summary of Technical Information in the Application The RWCU system maintains high reactor water purity to limit chemical and corrosive action and 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 removed
 
flow 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 and following DBEs. The failure of nonsafety-related SSCs in the RWCU system potentially could
 
prevent the satisfactory accomplishment of a safety-related function.
2-115 LRA Table 2.3.3-13-36 identifies the following RWCU system component types within the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* heat exchanger (shell)
* orifice
* piping
* pump casing
* strainer housing
* tank
* tubing
* valve body The RWCU system component intended function within the scope of license renewal is to provide 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 evaluation methodology 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 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).
The staff's review of LRA Section 2.3.3.13.2 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
The staff stated that license renewal drawing LRA-G-191178-SH-01-0, at location D-4, shows the 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 side
 
instrument 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 upstream piping and the common high side instrument lines are within the scope of license renewal based 2-116 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 Syst ems 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 acceptable because 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 in the 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 2.3.3.13m-1 The LRA states that the RWCU system is within the scope of license renewal in accordance 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 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.
The staff identified this as confirmatory item
>2.3.3.13m-1.
>In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License 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 ar e 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 2-117 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 applicant>stated NRC Regional Inspection Team found that if any nonsafety-related portion of a fluid
>system is located within a building containi ng 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 I confirmatory i tem 2.3.3.13m-1 is resolved.
>2.3.3.13M.3  Conclusion
 
The staff reviewed the LRA. RAI, and RAI and inspection confirmatory item 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
 
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).
2.3.3.13N 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 permits generator 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 the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-39 identifies the following stator cooling system component types within the scope of license renewal and subject to an AMR:
* bolting
* cooler
* filter housing
* heat exchanger (shell)
* piping
* pump casing
* strainer housing
* tank
* tubing
* valve body The stator cooling system component intended function within the scope of license renewal is to provide pressure boundary.
2-118 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-1 evaluation methodology 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 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).
2.3.3.13N.3  Conclusion
 
The staff reviewed the LRA 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 stator cooling 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).
2.3.3.13O HD & HV Instruments 2.3.3.13O.1  Summary of Technical Information in the Application The heater drain (HD) and the heater vent (HV) in struments system provides indication, alarm and control functions for associated systems (heater drains and heater vents).
The failure of nonsafety-related SSCs in the HD
& HV instruments system potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-43 identifies the following HD & HV instruments system component types within the scope of license renewal and subject to an AMR:
* bolting
* piping
* tubing
* valve body The HD & HV instruments system component intended function within the scope of license renewal 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 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 to verify 2-119 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).
2.3.3.13O.3  Conclusion
 
The staff reviewed the LRA 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 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).
2.3.3.13P Air Evacuation 2.3.3.13P.1  Summary of Technical Information in the Application The air evacuation (AE) system evacuates gas es from the main turbine and main condenser during startup and maintains them free of noncondensible gases during operation.
The failure of nonsafety-related SSCs in the AE sy stem potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-44 identifies the following AE system component types within the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* heat exchanger (shell)
* piping
* pump casing
* rupture disk
* strainer housing
* trap
* tubing
* valve body The AE system component intended function within the scope of license renewal is to provide pressure 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 evaluation methodology 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 and UFSAR to verify that the applicant has not omitted from the scope of license renewal any 2-120 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 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 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).
2.3.3.13Q Building (Drainage System Components) 2.3.3.13Q.1  Summary of Technical Information in the Application The building (BLD) system removes operational waste fluids from their points of origin in a controlled manner and delivers them to a suit able 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 the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-46 identifies the following BLD system component types within the scope of license renewal and subject to an AMR:
* bolting
* piping The BLD component intended function within the scope of license renewal is to provide pressure 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-1 evaluation methodology 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 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).
2.3.3.13Q.3  Conclusion 2-121 The staff reviewed the LRA 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 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 Application The circulating water priming (CWP) system prov ides air evacuation from the discharge side of the main condenser. The system ensures that air will not hinder circulating water flow by
 
collecting in the upper portions of the condenser water boxes or in the upper portion of the
 
circulating water discharge piping.
The failure of nonsafety-related SSCs in the CWP system potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-47 identifies the following CWP system component types within the scope of license renewal and subject to an AMR:
* bolting
* piping
* pump casing
* tank
* trap
* tubing
* valve body The CWP system component intended function within the scope of license renewal is to provide pressure 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-1 evaluation methodology 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 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).
2.3.3.13R.3  Conclusion
 
The staff reviewed the LRA 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 2-122 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 Application The extraction steam (ES) system supplies steam to the shell side of various feedwater heaters for 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.
The failure of nonsafety-related SSCs in the ES sy stem potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-48 identifies the following ES system component types within the scope of license renewal and subject to an AMR:
* bolting
* expansion joint
* orifice
* piping
* tubing
* valve body The ES system component intended function within the scope of license renewal is to provide pressure 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-1 evaluation methodology 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 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).
2.3.3.13S.3  Conclusion
 
The staff reviewed the LRA 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 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).
2-123 2.3.3.13T Heater Drain 2.3.3.13T.1  Summary of Technical Information in the Application The heater drain (HD) system provides proper level and control for the moisture separator and feedwater 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.
The failure of nonsafety-related SSCs in t he HD system potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-49 identifies the following HD system component types within the scope of license renewal and subject to an AMR:
* bolting
* piping
* pump casing
* tank
* tubing
* valve body The HD system component intended function within the scope of license renewal is to provide pressure 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-1 evaluation methodology 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 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).
2.3.3.13T.3  Conclusion
 
The staff reviewed the LRA 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 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).
2-124 2.3.3.13U Heater Vent 2.3.3.13U.1  Summary of Technical Information in the Application The heater vent (HV) system provides vent ing of non-condensable gases back to the main condenser.
The failure of nonsafety-related SSCs in the HV system potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-50 identifies the following HV system component types within the scope of license renewal and subject to an AMR:
* bolting
* orifice
* piping
* tank
* tubing
* valve body The HV system component intended function within the scope of license renewal is to provide pressure boundary.
2.3.3.13U.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.13.2, the Tier-1 evaluation methodology 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 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).
2.3.3.13U.3  Conclusion
 
The staff reviewed the LRA 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 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 Application The make-up demineralizer (MUD) system provides a supply of treated water that may be used as make-up for the station and reactor cycles. The MUD system consists of one train that 2-125 consists of a cation, anion, and a mixed bed ion exchanger.
The failure of nonsafety-related SSCs in the MUD system potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-53 identifies the following M UD system component types within the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* piping
* pump casing
* tank
* tubing
* valve body The MUD system component intended function within the scope of license renewal is to provide pressure 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-1 evaluation methodology 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 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).
2.3.3.13V.3  Conclusion
 
The staff reviewed the LRA 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 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 Application The seal oil (SO) system provides shaft sealing for the main generator.
 
The failure of nonsafety-related SSCs in the SO system potentially could prevent the satisfactory accomplishment of a safety-related function.
2-126 LRA Table 2.3.3-13-55 identifies the following SO system component types within the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* piping
* pump casing
* sight glass
* tank
* tubing
* valve body The SO system component intended function within the scope of license renewal is to provide pressure 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-1 evaluation methodology 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 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).
 
2.3.3.13W.3  Conclusion The staff reviewed the LRA 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 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 Application The turbine building closed cooling water (TBCCW) system supplies demineralized water to cool 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 the 2-127 satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-56 identifies the following TBCCW system component types within the scope of license renewal and subject to an AMR:
* bolting
* heat exchanger (shell)
* piping
* pump casing
* tank
* tubing
* valve body The TBCCW system component intended function within the scope of license renewal is to provide 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-1 evaluation methodology 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 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).2.3.3.13X.3  Conclusion
 
The staff reviewed the LRA 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 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 Application The main turbine generator (TG) system conver ts the thermodynamic energy of steam into electrical 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 the satisfactory accomplishment of a safety-related function.
2-128 LRA Table 2.3.3-13-57 identifies the following TG system component types within the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* piping
* pump casing
* turbine casing
* tubing
* valve body The TG system component intended function within the scope of license renewal is to provide pressure 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 evaluation methodology 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 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).
2.3.3.13Y.3  Conclusion
 
The staff reviewed the LRA 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 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 Application The 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 the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-58 identifies the following TLO system component types within the scope of license renewal and subject to an AMR:
* bolting
* filter housing
* heat exchanger (shell) 2-129
* piping
* pump casing
* strainer casing
* tank
* tubing
* valve body The TLO system component intended function within the scope of license renewal is to provide pressure 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-1 evaluation methodology 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 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).
2.3.3.13Z.3  Conclusion
 
The staff reviewed the LRA 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 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 Application The hydrogen water chemistry (HWC) system miti gates the chemical conditions that allow IGSCC 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 the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.3-13-51 identifies the following HWC system component types within the scope of license renewal and subject to an AMR:
* bolting
* piping
* tubing
* valve body 2-130 The HWC system component intended function within the scope of license renewal is to provide pressure 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 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).
2.3.3.13AA.3  Conclusion
 
The staff reviewed the LRA 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 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 renewal with 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
* 2.3.3.5SBFPC
* 2.3.3.6FO
* 2.3.3.7IA 2-131
* 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 Systems In LRA Section 2.3.4, the applicant identified the SCs of the steam and power conversion systems that are subject to an AMR for license renewal.
The applicant described the supporting SCs of the steam and power conversion systems in the following LRA Sections:
* 2.3.4.1auxiliary steam
* 2.3.4.2condensate
* 2.3.4.3main steam
* 2.3.4.4101 (main steam, extracti on 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 Steam 2.3.4.1.1  Summary of Technical Information in the Application LRA Section 2.3.4.1 describes the auxiliary steam (AS) system, which provides steam from MS piping 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 sy stem potentially could prevent the satisfactory 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 of license renewal and subject to an AMR:
* bolting
* condenser
* expansion joint
* heat exchanger (shell)
* heat exchanger (tubes)
* piping
* orifice
* strainer housing
* steam trap
* thermowell
* tubing 2-132
* valve body The AS system component intended functions within the scope of license renewal include the following:
* pressure boundary
* holdup and plateout of fission products 2.3.4.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.1 and UFSAR Section 11.4 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 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).
2.3.4.1.3  Conclusion
 
The staff reviewed the LRA and accompanying license renewal drawings 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 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  Condensate 2.3.4.2.1  Summary of Technical Information in the Application LRA Section 2.3.4.2 describes the condensate system, which receives condensed steam from the 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 singl e 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.
The failure of nonsafety-related SSCs in the c ondensate system potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Tables 2.3.4-1 and 2.3.3-13-2 identify the following condensate component types within the 2-133 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 body The condensate system component intended functions within the scope of license renewal include the following:
* pressure boundary
* holdup and plateout of fission products 2.3.4.2.2  Staff Evaluation
 
The staff reviewed LRA Sections 2.3.4.2 and 2.3.3.13, and UFSAR Section 11.8 using 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 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).
2.3.4.2.3  Conclusion
 
The staff reviewed the LRA 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 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).2.3.4.3  Main Steam 2.3.4.3.1  Summary of Technical Information in the Application LRA Section 2.3.4.3 describes the MS system, which completes the transmission of steam from 2-134 the seismic Class I steam piping to the main turbine at a controlled pressure during normal operation. The MS system consists of nonsaf ety-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 nece ssary. The main turbine bypass system has two valve chests, each with five automatically operated regulating bypass valves proportionally controlled by the turbine pressure regulat or and control system. The bypass system opens whenever the amount of steam admitted into t he 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 the satisfactory accomplishment of a safety-related function.
LRA Tables 2.3.4-1and 2.3.3-13-52 identify the following MS system component types within the 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 body The MS system component intended functions within the scope of license renewal include the following:
* pressure boundary
* holdup and plateout of fission products 2.3.4.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.3 and UFSAR Sections 11.4 and 11.5 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, 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).
2-135 2.3.4.3.3  Conclusion The staff reviewed the LRA and accompanying license renewal drawings 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 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 syst em (main steam, extr action steam, and auxiliary steam 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 t he 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, and auxiliary steam instruments) potentially could pr event the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.4-1 identifies the following 101 system (main steam, extraction steam, and auxiliary steam instruments) component types wi thin the scope of license renewal and subject to an AMR:
* bolting
* condenser
* orifice
* expansion joint
* heat exchanger (tubes)
* piping
* strainer housing
* thermowell
* steam trap
* tubing
* valve body The 101 (main steam, extraction steam, and auxilia ry steam instruments) component intended functions within the scope of license renewal include the following:
* pressure boundary
* holdup and plateout of fission products 2.3.4.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.4 using the Tier-1evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
2-136 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).
2.3.4.4.3  Conclusion
 
The staff reviewed the LRA and accompanying license renewal drawings 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 101 (main steam, extraction steam, and auxiliary steam instrum ents) 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: Structures This 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 commodities 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
 
SCs 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 structures. The objective 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 component drawings, 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 as
 
required by 10 CFR 54.4(a). The staff requested addi tional information to resolve any omissions 2-137 or discrepancies identified.
After its review of the scoping results, the staff evaluated the applicant's screening results. For those 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 Application LRA Section 2.4.1 describes the primary containment, which limits the release of fission products 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 to preclude 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 pers onnel 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
 
attach various system supports. The sacrificial shield wall provides lateral support for the
 
reactor 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 during and 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 scope of license renewal and subject to an AMR:
* steel and other metals
* concrete
* elastomers and other materials 2-138
* fluoropolymers and lubrite sliding surfaces The primary containment component intended functions within the scope of license renewal include the following:
* shelter or protection to safety-related equipment, including radiation shielding and pipe whip restraint
* protective barrier for flood events
* heat sink during SBO or DBAs
* missile barrier
* pressure boundary
* structural or functional support for safety-related equipment 2.4.1.2  Staff Evaluation The staff reviewed LRA Section 2.4.1 and UFSAR Sections 5.1.2 and 5.2 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4, "Scoping
 
and Screening Results: Structures."
The staff evaluated the structural component 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).
2.4.1.3  Conclusion The staff reviewed the LRA and related structural components 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 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 Application LRA Section 2.4.2 describes the reactor building, which in design basis accidents contains leakage 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 cl eanup demineralizer system, SLC system, CRD system equipment, reactor core and containment cooling systems, and electrical equipment 2-139 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 venti ng 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, is designed 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 fuel
 
storage 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 and following 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 of license renewal and subject to an AMR:
* steel and other metals
* concrete The reactor building component intended functions within the scope of license renewal include the following:
* shelter or protection to safety-related equipment, including radiation shielding and pipe whip 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 could impact safety-related equipment
* structural or functional support for safety-related equipment 2-140 2.4.2.2  Staff Evaluation The staff reviewed LRA Section 2.4.2 and UFSAR Sections 5.3, 10.4, and 12.2.2 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 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).
2.4.2.3  Conclusion The staff reviewed the LRA and related structural components 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 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 Application LRA Section 2.4.3 describes the intake structure, which supports and protects equipment that draws water from the intake canal, located east of the station on the riverbank and divided into
 
two rooms: the SW pump room (which also cont ains 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 on
 
bedrock. 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
 
warm discharge water by a concrete pipe connecting the discharge structure to the intake
 
structure keeps the intake bays and SW bays fr ee 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 and following 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 of license renewal and subject to an AMR:
* steel and other metals
* concrete The intake structure component intended functions within the scope of license renewal include 2-141 the following:
* shelter or protection to safety-related equipment, including radiation shielding and pipe whip 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 could impact 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 equipment 2.4.3.2  Staff Evaluation The staff reviewed LRA Section 2.4.3 and UFSAR Sections 10.6.5, 10.11.3, and 12.2.6 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 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 RAI 2.4.3-1 dated August 3, 2006, the staff stated that Table 2.4.3 does not include 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. 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 no license 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
 
2-142 The trash racks and traveling screens remove debris from the circulating and SW 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 renewal intended 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). Concrete pipe The concrete pipe connecting the intake structure to the discharge structure provides recirculation of warm condenser circulating water to keep the circulating
 
water 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 because the 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.
2-143 2.4.3.3  Conclusion The staff reviewed the LRA and related structural components 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 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 Application LRA Section 2.4.4 describes the process facilities, buildings or structures designated as either seismic 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 with major 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 an enclosure at its base contains monitoring equipment. The turbine building houses the TG
 
and 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 during and 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 of license renewal and subject to an AMR:
* steel and other metals
* concrete
* elastomer and other materials The process facilities component intended functions within the scope of license renewal include the following:
* shelter or protection to safety-related equipment, including radiation shielding and pipe whip restraint 2-144
* 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 could impact 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 equipment 2.4.4.2  Staff Evaluation The 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 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 RAI 2.4.4-1 dated August 3, 2006, the staff stated that Table 2.4-4 lists "Structural steel" as a component, 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 structural support 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 a building 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 2-145 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 because it 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 (cooling tower 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 results of 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, which initially 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 of license renewal,  provide the following:I.The potential effect of a circulating water piping, pipe supports, or structural failure 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 the circulating 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, pipe supports, or cooling tower cells.
In letters dated September 27 and October 18, 2007, the applicant provided the following response:Cooling Tower Background Information VYNPS utilizes once-through condenser cooling from the Connecticut River supplemented by two forced draft cooling towers. Each tower consists of eleven 2-146 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 cooling tower 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 Cell CT 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 is stainless steel, while the other towers may use carbon or galvanized
 
steel. The stainless steel hardware minimizes potential iron salt attack at
 
the bolted structural connections.
* Different level of quality. CT 2-1 and CT 2-2 are subject to the higher levels of oversight afforded to safety-related and Seismic Class I structures. 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 and higher level of quality, CT 2-1 and CT 2-2 have had more refurbishment during 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 license renewal. 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.
2-147 Cooling tower cell CT 2-1, which is part of the circulating water system, has the 10 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 RHRS W 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.
Response to Part B Subpart 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 constructed by 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 piping that 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 no system intended functions for 54.4(a)(1) or (a)(3). Pipe supports on this piping 2-148 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).
If the fiberglass piping were subject to aging management review, the aging management 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 is sufficient 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 involving collapse 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.
2-149 Failure of cooling tower cells CT 2-3 through CT 2-11 (9 of 11 cells) and associated components has no impact on safety-related cooling tower cell CT 2-
 
1.Subpart II:
 
As identified in the VYNPS LRA, the aging effects on the cooling tower wooden structures 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 ferrous hardware contacts the lumber and degrades the wood cells), (b)fungal attack (wood destroying microscopic organism called decay fungi that forms in wood exposed to suitable temperature 40 o F-140 o F in moist environment), and(c)repeated wetting and drying cycles causing wood checking and physical damage which reduces wood strength.
The circulating water piping within the cooling tower is made of fiberglass and is secured 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 reduction in 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 structural elements 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 2-150 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 2-1 and 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
 
assurance oversight and maintenance between cooling tower cells CT 2-1 through CT 2-2 and
 
those 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  Conclusion The staff reviewed the LRA and related structural components 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 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 Application LRA Section 2.4.5 describes the yard structures, structures not contained within the primary containment, 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 tank foundation 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 a 2-151 seismic 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 base of 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 of the 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 shutdown capability 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 known as the switchyard relay house, a single-story structure in the main switchyard, houses
 
relays 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 feet northwest 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 and following 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 of license renewal and subject to an AMR:
* steel and other metals
* concrete The yard structures component intended functions within the scope of license renewal include the following:
* shelter or protection to safety-related equipment, including radiation shielding and pipe whip restraint
* protective barrier for flood events
* missile barrier 2-152
* structural or functional support to nonsafety-related equipment the failure of which could impact 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 equipment 2.4.5.2  Staff Evaluation The staff reviewed LRA Section 2.4.5 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 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 RAI 2.4.5-1 dated August 3, 2006, the staff stated that Table 2.4.5 lists "Vernon Dam external 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 the outside 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 because it 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  Conclusion The staff reviewed the LRA and related structural components 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 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).
2-153 2.4.6  Bulk Commodities 2.4.6.1  Summary of Technical Information in the Application LRA Section 2.4.6 describes the bulk commodities, structural components or commodities that perform 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, inst rument panels and racks, cable trays, and conduits).
The bulk commodities have safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related bulk commodity SSCs potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the bulk
 
commodities 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 of license renewal and subject to an AMR:
* steel and other metals
* concrete
* elastomers and other materials
* fluoropolymers and lubrite sliding surfaces The bulk commodity component intended functions within the scope of license renewal include the following:
* shelter or protection to safety-related equipment, including radiation shielding and pipe whip 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 could impact 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 equipment 2.4.6.2  Staff Evaluation The staff reviewed LRA Section 2.4.6 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.
2-154 The staff evaluated the structural component 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 RAI 2.4.6-1 dated August 3, 2006, the staff stated that Table 2.4.6 lists "Flood curbs" as a component 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.
In its response dated September 5, 2006, the applicant provided the following response:
For VYNPS, flood curbs constructed of either concrete or steel perform the same intended 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 because the 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  Conclusion The staff reviewed the LRA and related structural components 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 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 ControlSystems This section documents the staff's review of the applicant's scoping and screening results for electrical 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. The objective was to determine whether the applicant has identified, as required by 10 CFR 54.4, components and supporting structures for EIC syst ems 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).
2-155 In its scoping evaluation, the staff reviewed the applicable LRA sections and component drawings, 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 as
 
required by 10 CFR 54.4(a). The staff requested addi tional information to resolve any omissions or discrepancies identified.
Once the staff completed its review of the scoping results, the staff evaluated the applicant's screening 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 Application LRA Section 2.5 describes the EIC systems. Plant EIC systems are included within the scope of license 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 fo r IPAs of mechanical systems and structures.
VYNPS electrical commodity groups correspond to two of the commodity groups identified in NEI 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 t he intended functions of commodity groups were examined. In addition to the plant electrical sy stems, 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 of license renewal and subject to an AMR:
* cable connections (metallic parts)
* electrical cables, connections, and fuse holders (insulation) not subject to 10 CFR 50.49 Environmental qualification requirements
* electrical cables not subject to 10 CFR 50.49 Environmental qualification requirements used in instrumentation circuits
* fuse holders (insulation material)
* high-voltage insulators 2-156
* inaccessible medium-voltage (4.16 kV to 22 kV) cables (e.g., installed underground in conduit or direct buried) not subject to 10 CFR 50.49 Environmental qualification
 
requirements
* switchyard bus
* transmission conductors The EIC systems component intended functions within the scope of license renewal include the following:
* provide electrical connections to specifi ed sections of an electrical circuit to deliver voltage, current, or signals
* insulate and support electrical conductor
 
====2.5.2 Staff====
Evaluation The staff reviewed LRA Section 2.5 and UFSAR Sections 7 and 8 using the evaluation methodology 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 and
 
Instrumentation 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 ground conductors 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, listed in LRA Table 2.2-1b, explaining how each syst em 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 and Control (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 assure s 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 because when used with "Plant Spaces"approach 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.
2-157 In RAI 2.5-2, the staff requested the applicant to provide details of Vermont Yankee Nuclear Power 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:
The parts of the AAC that are subject to AMR are explained in the response to RAI 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 disconnect
 
switch 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 dated July 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 by the 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 assemblies and 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, the staff 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.
2-158 In RAI 2.5-4, the staff asked the applicant to provide justification, in detail, why the cable connections (metallic portion) was not included in the scope of an AMR although the GALL Report aging management program XI.E6, "Ele ctrical 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:
Metallic parts of electrical cable connections that are exposed to thermal cycling and 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 stress
 
associated with electrical faults is not a credible aging mechanism because of
 
the low 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 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 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. Therefore, oxidation and
 
corrosion are not applicable aging mechanisms.
Electrical cable connections at VYNPS are inspected in accordance with the maintenance 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 exam inations, and preventive measures).
2-159 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.
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 (Commitment
>#42) as detailed in its letter dated January 4, 2007, the staff considers the issue raised in
>RAI 2.5-4 resolved.
 
====2.5.3 Conclusion====
The staff reviewed the LRA Section 2.5, the UFSAR, and the supplemental information provided 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 Screening The staff reviewed the information in LRA Section 2, "Scoping and Screening Methodology for
 
Identifying Structures and Components Subject to Aging Management Review and
 
Implementation 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).
2-160 On the basis of its review, the staff concludes, pending resolution of Confirmatory Items 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).
The staff concludes that there is reasonable assurance that the applicant will continue to conduct 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  3 AGING MANAGEMENT REVIEW RESULTS This section of the safety evaluation r eport (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 in LRA 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 Report In preparing its LRA, the applicant credited US NRC NUREG-1801, Volume 2, Revision 1, "Generic Aging Lessons Learned (GALL) R eport," 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 i ndicate 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 or monitor 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, the staff 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 im prove the efficiency and effectiveness of LRA review, while maintaining the staff's focus on public health and safety. NUREG-1800, Revision 1, "Standard Review Plan for Review of License Renewal Applications for Nuclear 3-2 Power 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 and associated 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 Application The applicant submitted an application that follows the standard LRA format agreed to by the staff 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 fo rmat 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 presents AMR results information in the following two table types:  (1)Table 1s: Table 3.x.1 - where "3" indicates the LRA Section number, "x" indicates the subsection number from the GALL Report, and "1" indicates that this 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 the subsection 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. The intent 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.
3.0.1.1  Overview of Table 1s Each Table 1 compares in summary how the facility aligns with the corresponding tables in the GALL 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 3-3"Discussion" column the applicant provided clarif ying 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 GALL Report when the consistency may not be obvious
* discussion of how the item is different from the corresponding line item in the GALL Report (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 the corresponding GALL Report table row so that the consistency can be checked easily.
3.0.1.2  Overview of Table 2s Each Table 2 provides the detailed results of the AMRs for components identified in LRA Section 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., reac tor 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 inje ction system (HPCIS), and residual heat removal system (RHRS). Each Table 2 consists of nine columns:  (1)Component Type - The first column lists LRA Section 2 component types subject to an AMR in alphabetical order.  (2)Intended Function - The second column identifies the license renewal intended functions, 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 the component type.  (4)Environment - The fourth column lists the environments to which the component types are exposed. Internal and external service env ironments 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 requiring management (AERM). As part of the AMR process, the applicant determined any
 
AERMs for each combination of material and environment.  (6)Aging Management Programs - The sixth column lists the AMPs that the applicant uses to 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 3-4 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 from LRA 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 the information 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 Process The 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 staff conducted either an audit or a technical review to determine such consistency.  (2)For items that the applicant stated were consistent with the GALL Report with exceptions, 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 GALL AMP 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 meet all 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 with 10 CFR 54.21(a)(3) requirements.
Staff audits and technical reviews of the applicant's AMPs and AMRs determine whether the effects 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.
3-53.0.2.1  Review of AMPs For AMPs for which the applicant claimed consis tency with the GALL AMPs, the staff conducted either 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 subject to an AMR for license renewal.  (2)Preventive Actions - Preventive acti ons should prevent or mitigate aging degradation.  (3)Parameters Monitored or Inspected - Parameters monitored or inspected should be linked to the degradation of the particular structure or component intended function(s).  (4)Detection of Aging Effects - Detection of aging effects should occur before there is a loss 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 the extent of degradation, as well as timely corrective or mitigative actions.  (6)Acceptance Criteria - Acceptance criteria, against which the need for corrective action will be evaluated, should ensure that the structure or component intended function(s) are
 
maintained in accordance with all CLB design conditions during the period of extended
 
operation.  (7)Corrective Actions - Corrective actions, including root cause determination and prevention of recurrence, should be timely.  (8)Confirmation Process - Confirmation process should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective.  (9)Administrative Controls - Administrative controls should provide for a formal review and approval process.  (10)Operating Experience - Operating ex perience of the AMP, including past corrective actions resulting in program enhancements or additional programs, should provide
 
objective evidence to support the conclusion that the effects of aging will be adequately
 
managed so that the SC intended function(s) will be maintained during the period of
 
extended operation.
Details of the staff's audit evaluation of program elements (1) through (6) are documented in SER Section 3.0.3.
The staff reviewed the applicant's quality assurance (QA) program and documented its evaluations in SER Section 3.0.4. The staff's evaluation of the QA program included
 
assessment of the "corrective actions," "confir mation process," and "administrative controls" program elements.
3-6 The staff reviewed the information on the "operating experience" program element and documented its evaluation in SER Section 3.0.3.
The staff reviewed the Updated Final Safety Analysis Report (UFSAR) Supplement for each AMP to determine if it provided an adequate description of the program or activity, as required
 
by 10 CFR 54.21(d).3.0.2.2  Review of AMR Results Each LRA Table 2 contains information concerning whether or not the AMRs identified by the applicant 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 co lumn 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 Supplement Consistent with the SRP-LR for the AMRs and AMPs that it reviewed, the staff also reviewed the 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 Reviewed In 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 the applicant's activities and programs will adequately manage the effects of aging on SCs. The
 
staff also conducted detailed discussions and interviews with the applicant's license renewal
 
project personnel and others with technical expertise relevant to aging management.
 
====3.0.3 Aging====
Management Programs SER Table 3.0.3-1 presents the AMPs credited by the applicant and described in LRA Appendix B and subsequent LRA supplements. The table also indicates the SSCs that credit
 
the 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 Report ComparisonGALL ReportAMPsLRA Systems or StructuresThat Credit the AMP Staff's SER SectionExisting AMPs VYNPS AMP(LRA Section)GALL Report ComparisonGALL ReportAMPsLRA Systems or StructuresThat Credit the AMP Staff's SER Section 3-7 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 with exceptions and
 
enhancementsXI.M34ESF systems / auxiliarysystems 3.0.3.2.1 BWR CRD Return Line Nozzle Program (B.1.2)Consistent with exceptionXI.M6reactor vessel, internals, andreactor coolant system 3.0.3.2.2BWR Feedwater Nozzle Program (B.1.3)Consistent with exceptionXI.M5reactor vessel, internals, andreactor coolant system 3.0.3.2.3BWR Penetrations Program (B.1.4)Consistent with exceptionsXI.M8reactor vessel, internals, andreactor coolant system 3.0.3.2.4 BWR Stress Corrosion Cracking Program (B.1.5)Consistent with exceptionXI.M7reactor vessel, internals, andreactor coolant system 3.0.3.2.5 BWR Vessel Inside Diameter Attachment Welds Program (B.1.6)Consistent with exceptionXI.M4reactor vessel, internals, andreactor coolant system 3.0.3.2.6 BWR Vessel Internals Program (B.1.7)Consistent with exceptions and
 
enhancementsXI.M9reactor vessel, internals, andreactor coolant system 3.0.3.2.7 Containment Leak Rate Program (B.1.8)Consistent with exceptionXI.S4ESF systems / SC supports 3.0.3.2.8Diesel Fuel Monitoring Program (B.1.9)Consistent with exceptions and
 
enhancementsXI.M30auxiliary systems 3.0.3.2.9 Environmental Qualification of Electric
 
Components Program (B.1.10)ConsistentX.E1electric al and instrumentation and controls 3.0.3.1.1Fatigue Monitoring Program (B.1.11)Consistent with exceptions and
 
enhancementsX.M1reactor vessel, internals, andreactor coolant system / ESF systems / auxiliary systems /
steam and power conversion systems / SC supports 3.0.3.2.10Fire Protection Program (B.1.12.1)Consistent with exceptions and
 
enhancementsXI.M26auxiliary systems / SC supports 3.0.3.2.11 VYNPS AMP(LRA Section)GALL Report ComparisonGALL ReportAMPsLRA Systems or StructuresThat Credit the AMP Staff's SER Section 3-8Fire Water System Program (B.1.12.2)Consistent with exception and
 
enhancementsXI.M27auxiliary systems 3.0.3.2.12Flow-Accelerated Corrosion Program (B.1.13)ConsistentXI.M17reactor vessel, internals, andreactor coolant system / ESF systems / auxiliary systems /
steam and power conversion systems 3.0.3.1.2 Containment Inservice Inspection Program (B.1.15.1)Plant-specificNASC supports 3.0.3.3.2 Inservice Inspection Program (B.1.15.2)Plant-specificNAreactor vessel, internals, andreactor coolant system / SC
 
supports 3.0.3.3.3 Instrument Air Quality Program (B.1.16)Plant-specificNAauxiliary systems 3.0.3.3.4Oil Analysis Program (B.1.20)Consistent with exceptionXI.M39ESF systems / auxiliarysystems 3.0.3.2.13 Periodic Surveillance and Preventive
 
Maintenance Program (B.1.22)Plant-specificNAESF systems / auxiliarysystems / SC supports 3.0.3.3.5 Reactor Head Closure Studs Program (B.1.23)ConsistentXI.M3reactor vessel, internals, andreactor coolant system 3.0.3.2.14 Reactor Vessel Surveillance Program (B.1.24)Consistent with enhancementXI.M31reactor vessel, internals, andreactor coolant system 3.0.3.2.15 Service Water Integrity Program (B.1.26)Consistent with exceptions and
 
enhancement.XI.M20ESF systems / auxiliarysystems 3.0.3.2.16Masonry Wall Program (B.1.27.1)ConsistentXI.S5SC supports 3.0.3.1.8 Structures 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 3.0.3.1.9 VYNPS AMP(LRA Section)GALL Report ComparisonGALL ReportAMPsLRA Systems or StructuresThat Credit the AMP Staff's SER Section 3-9 Water Chemistry Control - Auxiliary Systems Program (B.1.30.1)Plant-specificNAESF systems / auxiliarysystems 3.0.3.3.7 Water Chemistry Control - BWR
 
Program (B.1.30.2)ConsistentXI.M2reactor vessel, internals, andreactor coolant system / ESF systems / auxiliary systems /
steam and power conversion systems / SC supports 3.0.3.1.11 Water Chemistry Control - Closed Cooling Water Program (B.1.30.3)Consistent with exceptionXI.M21reactor vessel, internals, andreactor coolant system / ESF systems / auxiliary systems /
steam and power conversion systems 3.0.3.2.18New AMPs Heat Exchanger Monitoring Program (B.1.14)Plant-specificNAESF systems / auxiliarysystems 3.0.3.3.1 Non-Environmental Qualification
 
Inaccessible
 
Medium-Voltage Cable
 
Program (B.1.17)ConsistentXI.E3electri cal and instrumentation and controls 3.0.3.1.3 Non-Environmental Qualification
 
Instrumentation Circuits Test Review Program (B.1.18)ConsistentXI.E2electri cal and instrumentation and controls 3.0.3.1.4 Non-Environmental Qualification Insulated
 
Cables and
 
Connections Program (B.1.19)ConsistentXI.E1electri cal and instrumentation and controls 3.0.3.1.5One-Time Inspection Program (B.1.21)ConsistentXI.M32XI.M35 reactor vessel, internals, andreactor coolant system / ESF systems / auxiliary systems
/steam and power conversion systems 3.0.3.1.6 Selective Leaching Program (B.1.25)ConsistentXI.M33ESF systems / auxiliarysystems 3.0.3.1.7 VYNPS AMP(LRA Section)GALL Report ComparisonGALL ReportAMPsLRA Systems or StructuresThat Credit the AMP Staff's SER Section 3-10Thermal Aging and Neutron Irradiation
 
Embrittlement of Cast
 
Austenitic Stainless
 
Steel Program (B.1.29)ConsistentXI.M13reactor vessel, internals, andreactor coolant system 3.0.3.1.10 Metal-Enclosed Bus Inspection Program (B.1.32)Consistent with exceptionsXI.E4electrical and instrumentation and controls 3.0.3.2.20 Bolted Cable Connections Program (B.1.33)Plant-specificNAelectric al and instrumentation and controls 3.0.3.3.83.0.3.1  AMPs Consistent with the GALL Report In LRA Appendix B, the applicant identified the following AMPs as consistent with the GALL Report:
* 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
* System Walkdown Program
* Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program
* Water Chemistry Control - BWR Program 3.0.3.1.1  Environmental Qualification of Electric Components Program Summary of Technical Information in the Application. LRA Section B.1.10 describes the existing Environmental 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 component thermal, 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 3-11 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 of consistency 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 the aging 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 the qualification 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, or in the application of a component (de-energized versus energized). The
 
re-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 aging evaluation 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 3-12 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 the component 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 evaluation contain 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.
Acceptance Criteria and Corrective Actions: The re-analysis of an aging evaluation 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 in the 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 3-13 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 will
 
continue 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 reflec t 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 of Electric Components Program is an existing pr ogram 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 environm ental qualification program provided assurance of aging management of thermal, radiation, and cy clical for electrical equipment, important to safety and located in harsh environments. The staff finds the applicant's Environmental
 
Qualification of Electric Components Program acceptable because it conformed to the recommended GALL AMP X.E1, "Environmental Q ualification of Electric Components."
Operating Experience. LRA Section B.1.10 states that Licensee Event Report 97-20 notified the staff 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 proc ess 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 the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any 3-14 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 will adequately manage the aging effects that are identified in the LRA for which this AMP is credited.
The staff confirmed that the "operating ex perience" 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.2.1.10, the applicant provided the UFSAR supplement for 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 of Electric 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).
3.0.3.1.2  Flow-Accelerated Corrosion Program
 
Summary 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 in systems 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 of consistency with the GALL Report. The Audit and Review Report details the staff's evaluation of
 
this AMP.The staff reviewed the VYNPS F f low-accelerated corrosion procedures and noted which states
>that VYNPS performs 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 F f low-accelerated corrosion
>procedure acceptance criteria.
>
3-15 The impact of the 20 percent increased power level on F f low-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 wall
>thickness changes due to F f low-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 in part on the predictive
>computer code CHECWORKS.
CHECWORKS is used as a bases for selecting steel piping components for inspection and inspecting those components in accordance with ultrasonic testing (UT) techniques. The staff
 
determined that the applicant's application of the CHECWORKS computer code uses plant
 
operating characteristics, operating parameters, and actual UT inspection results to establish a
 
ranking of the susceptibility of the plant's steel components to wall thinning by flow-accelerated
 
corrosion. It is used to predict the amount of wear that will occur in the in-scope steel
 
components. The staff determined that the applicant incorporates the results of its UT
 
inspections into the CHECWORKS modeling to confirm the wear rate predictions.
The staff noted that the applicant also uses VY-specific 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
,>industry-wide operating experience, and engineering judgment as additional bases for selecting
 
the steel piping, piping components, and piping elements for inspection as part of the AMP. The
 
staff verified that the Flow-Accelerated Corrosion Program and finds that after change the
>parameters remain in the range that was benchmarked. The includes applicable acceptance
>criteria for evaluating in-scope components and applicable corrective actions (repair, replacement, or re-evaluation) for components that are projected to exhibit an unacceptable
 
amount of wall thinning. The staff finds this approach for aging management to be acceptable
 
because it is in conformance with the staff's recommended program element criteria for aging management in GALL Report AMP XI.M17, "Flow-Accelerated Corrosion."
Based on this review, the staff conclude d s 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 program elements for the applicant's modified Flow--Accelerated
>Corrosion Program provide an adequate basis to manage flow-accelerated corrosion because:
>(1) CHECWORKS code is considered to be a benchmarked code that is capable of modeling, predicting, and tracking the results of the ultrasonic inspections that are performed in
 
accordance with the applicant's Flow-Accelerated Corrosion Program, (2) the applicant uses the
 
actual UT inspection results to confirm the predictive analyses, (3) the applicant does not limit
 
the use of the CHECWORKS computer code as the sole basis for establishing which VY-
 
specific steel piping, piping components, or piping elements will be inspected, and (4) the 3-16 program includes acceptable program elements for managing flow-accelerated corrosion that
>are consistent with the program element criteria in GALL Report AMP XI
. M17.>The staff reviewed those portions of the applicant's Flow-Accelerated Corrosion Program for which the applicant claimed consistency with GALL Report AMP XI.M17 and found that they are
>consistent with this GALL Report 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 F f low-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 conform ed s to the recommended GALL Report AMP XI.M17 , "Flow-Accelerated
>Corrosion.">Operating Experience. LRA Section B.1.13 states that recent inspection results (refueling outage (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 have been
 
effective in mitigating Flow-Accelerated C flow-accelerated c orrosion 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 that monitors 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-Acce lerated 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 the CAP 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 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 applicant's
 
Flow-Accelerated Corrosion Program, with the corrective actions and enhancements post EPU>modifications mentioned above, has been effective in identifying, monitoring, and correcting the
>effects of F f low-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's technical 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.
3-17 The staff confirmed that the "operating ex perience" 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.2.1.14, the applicant provided the UFSAR supplement for 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 Corrosion 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).
3.0.3.1.3  Non-Environmental Qualificati on Inaccessible Medium-Voltage Cable Program Summary of Technical Information in the Application. LRA Section B.1.17 describes the new Non-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 and conduit 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 of consistency 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 program element, 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 3-18 applicant to explain how actual plant experience was considered in the manhole inspection frequency, as consistent with the GALL Report's recommendation. In its response, the applicant
 
stated that Non-EQ Inaccessible Medium-Volt age Cable Program will be revised to include the following:
VYNPS inspection for water accumulation in manholes is conducted by a plant procedure. 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 experience will 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 inaccessible
 
medium-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-Volt age Cable Program is to test in-scope cables and inspect 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-environmental qualification inaccessible medium-voltage cables within the scope of license renewal. The staff
 
asked 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 parameters monitored/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 3-19 at the time the test is performed. In the program basis document, in accordance with the same attribute, 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 test and 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 GALL Report 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 a voltage level from 2kV to 35kV. The applicant's Non-EQ Inaccessible Medium-Voltage Cable Program defines a medium-voltage cable as havi ng 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 cables
 
with 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 issued RAI 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 Qualification Inaccessible Medium-Voltage Cable Program for which the applicant claimed consistency with GALL 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 a ssurance of aging management of conductor insulation due to significant moisture while energized. The staff finds the applicant's
 
Non-Environmental Qualification Inaccessibl e Medium-Voltage Cable Program acceptablebecause it conforms to the recommended GALL AMP XI.E3, "Inaccessible Medium-Voltage
 
Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements."
3-20 Operating Experience. LRA Section B.1.17 states that there is no operating experience for the new Non-Environmental Qualification I naccessible Medium-Voltage Cable Program.During the audit and review, the staff noted that GALL AMP X1.E3, in accordance with operating experience, 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 the program 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 assu rance 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 the plant-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 operating experience 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.
3-21 The operating experience program procedure includes the following components:
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.
Internal operating experience - Operating experience 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.
Impact Evaluation - Analysis of an operat ing 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. 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'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 confirmed that the "operating ex perience" program element satisfies the recommendation 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 for the Non-Environmental Qualification I naccessible Medium-Voltage Cable Program.
The applicant committed (Commitment #13) to impl ement 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-Environmental Qualification 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).
3-22 3.0.3.1.4  Non-Environmental Qualification Instrumentation Circuits Test Review Program Summary of Technical Information in the Application. LRA Section B.1.18 describes the new Non-Environmental Qualification Instrumentati on Circuits Test Review Program as consistentwith 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 Instrumentat ion Circuits Test Review Program will assure maintenance of the intended functions of instru ment 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 se vere 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 of consistency 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 or surveillance 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 during instrument 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 be considered 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.The staff also noted that GALL AMP XI.E2, in accordance with the corrective actions program element, 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.
3-23 The applicable program basis document, in accordance with the same program element, only referred 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 consistent
 
with current license basis." This evaluation is performed in accordance with the Entergy
 
corrective action process procedure. This procedur e 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 this program 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 an AMR. 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 response
 
acceptable 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/inspected program 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 Instrumentation Circuits Test Review Program
 
basis document will be revised in accordance with the 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 3-24 staff finds the applicant's response acceptable because the revised parametersmonitored/inspected program element is consistent with GALL AMP XI.E2.
The staff reviewed those portions of the applicant's Non-Environmental Qualification Instrumentation Circuits Test Review Program for which the applicant claimed consistency withGALL 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 staff
 
finds the applicant's Non-Environmental Qualif ication Instrumentation Circuits Test ReviewProgram 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 the new Non-Environmental Qualification Instrument ation Circuits Tests Review Program. Industry and plant-specific operating experience will be cons idered 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 the operating 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. The
 
vast majority of site specific and industry wide operating experience regarding neutron flux
 
instrumentation circuits is related to cable/connector issues inside containment near the reactor
 
vessel. 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 the program 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 assu rance 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 the plant-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.
3-25 The applicant also stated that operating experience at VYNPS is controlled by its operating experience 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 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.
Internal operating experience - Operating experience 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.
Impact Evaluation - Analysis of an operat ing 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. 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'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 ex perience" 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.2.1.20, the applicant provided the UFSAR supplement for the Non-Environmental Qualification Instrumentation Circuits Test Review Program.
The applicant committed (Commitment #14) to impl ement its Non-Environmental Qualification Instrumentation Circuits Test Review Program by March 21, 2012.
The staff reviewed LRA Section A.2.1.20 and determined that, upon the implementation of Commitment #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-Environmental Qualification Instrumentation Circuits Test Revi ew Program, the staff finds all program elements 3-26 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 new Non-Environmental Qualification Insulated Cabl es and Connections Program as consistent withGALL AMP XI.E1, "Electrical Cables and Connections Not Subject to 10 CFR 50.49
 
Environmental Qualification Requirements."
The Non-Environmental Qualification Insulat ed Cables and Connections Program will assure maintenance 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 si gnificantly 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 of consistency 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 that the 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
 
Non-EQ Insulated Cables and Connections Program in accordance with the same element, the
 
applicant 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 C ables and Connections Program would be revised to read as follows:
3-27 This program addresses cables and connections at plants whose configuration is such 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 for cable 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 the inspection program applies to accessible electrical cables and connections within the scope of
 
license renewal that are installed in adverse lo calized environment caused by heat or radiation in the presence of oxygen. The Non-EQ Insulat ed 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 the scope 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.
The staff reviewed those portions of the applicant's Non-Environmental Qualification Insulated Cables and Connections Program for which t he applicant claimed consistency with GALLAMP 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 agi ng 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.
3-28 Operating Experience. LRA Section B.1.19 states that there is no operating experience for the new Non-Environmental Qualification In sulated Cables and Connections Program.During the audit and review, the staff noted that GALL AMP XI.E1 stated that operating experience 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 that forms 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 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 the plant-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 operating experience 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.
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 that describes events, issues, equipment failures, that may represent opportunities to 3-29 apply lessons learned to avoid negative consequences or to recreate positive experience as applicable.
Internal operating experience - Operating experience 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.
Impact Evaluation - Analysis of an operat ing 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. 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'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 confirmed that the "operating ex perience" 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.2.1.21, the applicant provided the UFSAR supplement for the Non-Environmental Qualification Insulated Cables and Connections Program.
The applicant committed (Commitment #15) to implement its Non-EQ Insulated Cables and Connections Program by March 21, 2012.
The staff reviewed LRA Section A.2.1.21 and determined that, upon the implementation of Commitment #15, 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-Environmental Qualification 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).
3-30 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 implem ented prior to the period of extended operation.
The one-time inspection activity for small-bore piping in the reactor coolant system and
 
associated systems that form the reactor c oolant pressure boundary (RCPB) will be comparableto 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 the reactor 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 an assessment 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 examinat ions to monitor the progression of any aging degradation.
Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency 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 bore piping 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 3-31 opportunity not occur (e.g., socket weld failure or socket weld replacement), a susceptible small-bore socket weld will be examined either destr uctively 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 examination of 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 references to socket welds.
In addition, as discussed further in SER Sections 3.2.2.1.3 and 3.3.2.1.9, the applicant provided an 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 a one-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."Operating Experience. LRA Section B.1.21 states that there is no operating experience for the new 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 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.
3-32 The staff confirmed that the "operating ex perience" 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.2.1.23, the applicant provided the UFSAR supplement for the One-Time Inspection Program.
In addition, the applicant stated in a letter dated January 4, 2007, that a one-time inspection activity 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 by March 21, 2012.
The staff reviewed LRA Section A.2.1.23 and determined that, upon the implementation of Commitment #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 Inspection Program, 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
 
components to perform their intended function for 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 of consistency with the GALL Report. The Audit and Review Report documents the details of the
 
staff's evaluation of this AMP.
3-33 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 the new Selective Leaching Program.
The staff audited VYNPS maintenance data for evidence of this aging mechanism and reviewed the 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 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.2.1.27, the applicant provided the UFSAR supplement for the Selective Leaching Program.
The applicant committed (Commitment #19) to im plement its Selective Leaching Program by March 21, 2012.
The staff reviewed LRA Section A.2.1.27 and determined that, upon the implementation of Commitment #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).
3.0.3.1.8  Masonry Wall Program
 
Summary of Technical Information in the Application. LRA Section B.1.27.1 describes the existing 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 evaluation basis 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 3-34 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 of consistency 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, in accordance 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 intended function between inspections. The inspection frequency may vary from wall to
 
wall, depending on the significance of cracking in the evaluation basis.
 
Unreinforced masonry walls, 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 license renewal, 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 operating experience 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 Wall Programfor 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 of masonry
 
block walls will be properly managed for the period of extended operation. The staff finds 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 effectiv eness. The listed operating experience in which 3-35 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 renewal and 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'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 confirmed that the "operating ex perience" 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.2.1.29, the applicant provided the UFSAR supplement for the 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, 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).
3.0.3.1.9  System Walkdown Program
 
Summary of Technical Information in the Application. LRA Section B.1.28 describes the existing System 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. 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.
Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The Audit and Review Report details the staff's 3-36 evaluation of this AMP.
The staff noted that, the applicant's System Walkdown procedure, one of the specific purposes of 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 System Walkdown 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 t he 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 accept able because it conformed to the recommendedGALL AMP XI.M36, "External Surfaces Monitoring."
Operating Experience. LRA Section B.1.28 states that in 1999 a self-assessment determined that 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 t hat system engineering management had not used metrics sufficient for monitoring core functions of the department. In accordance with new
 
oversight standards supervisors perform walkdow ns 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, and air-conditioning (HVAC) systems have detected leakage or degradation prior to loss of
 
intended 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 operating experience program that monitors industr y 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. Thos e 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 walkdowns indicated 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 3-37 program included thermography of plant instrum entation and the electrical components in theswitchyard.
The staff also reviewed the operating experience provided to confirm that the plant-specific operating experience did not reveal any degr adation 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 Pr ogram appropriately. This should help ensure that the System Walkdown Program will manage the e ffects of aging in the systems and components for which the program is credited.
The staff confirmed that the "operating ex perience" 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.2.1.32, the applicant provided the UFSAR supplement for the System Walkdown Program.
The applicant committed (Commitment #24) to have the System Walkdown guidance document enhanced to perform periodic system engineer inspec tions 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 subjec t 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 Walkdown Training 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 to specify CO 2 system inspections every six months; by March 21, 2012.
The 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 Stainless Steel Program 3-38 Summary of Technical Information in the Application. LRA Section B.1.29 describes the new Thermal 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 Austenitic Stainless 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 vesse l 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 of consistency 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 Irradiation Embrittlement of Cast Austenitic Stainless Steel Program for which the applicant claims consistency with GALL AMP XI.M13 and found that t hey 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)."
Operating Experience. LRA Section B.1.29 states that there is no operating experience for the new Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel
 
Program.The staff reviewed the operating experience provided in the program basis document, and interviewed 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 ex perience" 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.
3-39 UFSAR Supplement. In LRA Section A.2.1.33, the applicant provided the UFSAR supplement for the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel
 
Program.The applicant committed (Commitment #25) to implement its Thermal Aging and Neutron Irradiation 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 of Commitment #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 Neutron Irradiation 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 the existing 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 cracking mechanisms. 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
 
Chemistry Control - BWR Program optimizes t he primary water chemistry to minimize the potential 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 of consistency 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 a ssurance that this program will help mitigate degradation caused by corrosion and stress corrosion cracking (SCC) in components exposed to 3-40 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 Cycle 24 (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 chemical
 
ingress, 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 external organization 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 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 ex perience" 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.2.1.35, the applicant provided the UFSAR supplement for the 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 to explicitly 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 Enhancements 3-41 In LRA Appendix B, the applicant stated the following AMPs that are, or will be, consistent with the 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 For 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. The
 
staff 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 supplement dated 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 to manage 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.
3-42 Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency 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 the applicantclaimed 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 m anage 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 Report program element "scope of program." Spec ifically, the exception states that:
The GALL Report refers to buried steel piping and tanks. The VYNPS program does 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 that are in accordance with standard industry practices.
The staff asked the applicant to describe the tanks at VYNPS. The applicant responded that the only below-grade tank at VYNPS that is below grade is the diesel fire pump tank, which is in a
 
vault, so it is not exposed to a soil environment. The only buried tank at VYNPS is the John
 
Deere 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 at VYNPS 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 M onitoring Program, the staff found this exception acceptable.
Exception 2. In LRA Section B.1.1, the applicant stated an exception to the GALL Report program element "detection of aging effect s." Specifically, the exception states:
Inspections via methods that allow assessment of pipe condition without excavation 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 to examine 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.
3-43 The staff asked the applicant to provide technical justification of the phased array UT examination 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 exam inations 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 exam ination 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 in
>meeting the GALL Report program element "paramet ers monitored/inspected." Specifically, the enhancement stated (Commitment # 1):
Guidance for performing examinations of buried piping will be enhanced to specify that coating degradation and corrosion are attributes to be evaluated.
The applicant further stated, in the LRA, that this program included examinations to detect and manage 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 for obvious 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 additi onal 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 underneath
 
failed 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 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.Enhancement 2. In LRA supplement dated March 23, 2007, the applicant stated the following
>enhancement in meeting the GALL Report program element "detection of aging effects."
Specifically, the enhancement stated:
3-44 Program guidance will be revised to include the following. "A focused inspection will 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 - NRC License 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 inspected on 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.
The applicant stated, during the audit and review, that VYNPS has a comprehensive operating experience program that monitors industr y 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. Thos e 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'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 confirmed that the "operating ex perience" 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.2.1.1, the applicant provided the UFSAR supplement for the Buried Piping Inspection Program.
In LRA Section A.2.1.1, the applicant stated that its Buried Piping Inspection Program included 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 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. 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.
3-45 A focused inspection will 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.
(Commitment #44).
During the audit and review, the staff asked the applicant to clarify its buried piping examination plans 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 opportunist ic examination or an examination by an examination method that allows an assessment of the buried piping surface condition without
 
excavation, occurs within that ten-year period.
The applicant committed (Commitment #1) to enhance guidance for performing examinations of buried 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 of Commitment #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 Inspection Program, 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 existing BWR CRD Return Line Nozzle Program as consist ent, 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 reactor water 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.
3-46 Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency 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 program elements "parameters monitored/inspected," "detection of aging effects," and "monitoring and
 
trending." Specifically, the exception states:
VYNPS does not inspect the welded connection between the CRD return line and the 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 of extended 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 and Control 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 ultrasonic examination in October 2002 found no indications of cracking.
The staff reviewed plant records of the examinations identified in the LRA, and interviewed the 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 3-47 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 ex perience" 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.2.1.2, the applicant provided the UFSAR supplement for the 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 Nozzle 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 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 valve with a drag-type valve with improved flow c haracteristics, 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 of consistency 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 the applicantclaimed 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.
3-48 Exception. In LRA Section B.1.3, the applicant stated an exception to the GALL Report program element "preventive actions." Spec ifically, the exception states:
Stainless steel cladding was not removed, a low-flow controller was not installed and the RWCU system was not rerouted.
The LRA further states that VYNPS performs the enhanced ISI recommended by a GE guidance document 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 inservice inspection 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
 
and determined that the intent of the requirements of NUREG-0619 and NEDE-21821-A had
 
been satisfied by the modifications performed.
The staff finds that FW nozzle cracking continues to be adequately managed by the existing program. On this basis, the staff finds this exception to be acceptable.
Operating Experience. Section B.1.3, states that inspections following FW system modifications show 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'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. 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 ex perience" 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.2.1.3, the applicant provided the UFSAR supplement for the 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 Nozzle 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 determined that the AMP, with the exception, is adequate to manage the 3-49 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 existing BWR Penetrations Program as consistent, with exceptions, with GALL AMP XI.M8, "BWR Penetrations."
The program includes: (a) inspection and flaw evaluation conforming to the guidelines of staff-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 of consistency 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 that maintaining 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 is acceptable. 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 program elements "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.
3-50The applicant further stated, in the LRA, that "Since ASME Code, Section XI through the 2003 Addenda 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 penetration inspection requirements in IWB-2500 for the ASME Code Edition/Addendum identified in this
 
exception. On this basis, the staff finds this acceptable.
Exception 2. In LRA Section B.1.4, the applicant stated exception to the GALL Report program element "detection of aging effects." Specifically, the exception states:
VYNPS examines 1/2 inch of the volume next to the widest part of the N10 nozzle to 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 referencing examination 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 ASME Code Case N-613-1, the
 
staff finds this exception acceptable.
Operating Experience. LRA Section B.1.4 states that enhanced leakage inspection (with insulation 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 operating experience 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.
3-51 The staff confirmed that the "operating ex perience" program element satisfies the recommendation 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 for the 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).
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 flaw evaluation to monitor IGSCC and its effect s 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 of consistency 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 that maintaining 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 is acceptable. 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 applied throughout 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.
3-52 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.
Exception. In LRA Section B.1.5, the applicant stated an exception to the GALL Report program element "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 has been 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. The acceptance 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 ultrasonic examinations 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, including replacement 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'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 ex perience" 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.
3-53 UFSAR Supplement. In LRA Section A.2.1.5, the applicant provided the UFSAR supplement for the 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 Corrosion Cracking 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
 
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).
3.0.3.2.6  BWR Vessel ID Attachment Welds Program
 
Summary of Technical Information in the Application. LRA Section B.1.6 describes the existing BWR 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 of staff-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 of consistency 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 that maintaining 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 is acceptable. 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 welds which 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.
3-54 The staff reviewed those portions of the BWR Vessel ID Attachment Welds Program for which the 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 assu rance 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
 
ID Attachment Welds Program acceptable because it conforms to the recommended GALL AMP 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 program element "parameters monitored/inspected.
" Specifically, the exception states:Table IWB-2500-1 from the 1998 Edition with 2000 Addenda of ASME Section XI is 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 2003 Addenda 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. The acceptance 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 attachment welds 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'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 ex perience" 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.2.1.6, the applicant provided the UFSAR supplement for the 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).
3-55 Conclusion. On the basis of its audit and review of the applicant's BWR Vessel ID Attachment Welds 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
 
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).
3.0.3.2.7  BWR Vessel Internals Program
 
Summary of Technical Information in the Application. LRA Section B.1.7 describes the existing BWR 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 of consistency 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 dryer in 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 that maintaining 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 is acceptable. 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 3-56 AMP. Furthermore, the staff concludes that the applicant's BWR Vessel Internals Program provided assurance that aging effects for vesse l internals will be managed so that the systems and components within the scope of this program will continue to perform their intended
 
functions consistent with the CLB 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 Report program 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 18 inches 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 H1 and 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 from the 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 the exception 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 core shroud (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's recommendation, consistent with the GALL Report recommendation, the staff finds this
 
acceptable.
3-57 Exception 2. In LRA Section B.1.7, the applicant stated exception to the GALL Report program elements "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 the core 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 bolted connections 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 to address 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-specific analysis 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 Report program elements "scope of program" and "detection of aging effects." Specifically, the exception states that:
Core Spray - VYNPS defers inspection of the three inaccessible welds inside each 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.
3-58 The applicant stated, in the LRA, that "The three CS thermal sleeve welds in each of the two CS nozzles 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. In this 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 Report program 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 welds with 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 system for 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 these welds 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.
3-59 For jet pump welds, BWRVIP-41 finds EVT-1 or UT to be acceptable examination techniques. 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. In this 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 no way 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. The first 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 is
 
that 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 staff has 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.
3-60 Exception 5
. In LRA Section B.1.7, the applicant stated an exception to the GALL Report program 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 CRD guide 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 inspect 5 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 performed and 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 CRGT over 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 Report program element "parameters monitored/inspect ed." 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 Addenda 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."
3-61 The staff reviewed the Inservice Inspection Program and concludes that it is acceptable. The acceptance 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 meeting the 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 the period 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 fo r 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 first 12 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 is implemented, 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 eval uated in accordance with BWRVIP-18 evaluation criteria 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 effe ctive 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 BWR Vessel 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.
The staff reviewed the 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 3-62 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 ex perience" 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.2.1.7, the applicant provided the UFSAR supplement for the BWR Vessel Internals Program.
The applicant committed (Commitment #37) to continue inspections in accordance with the steam 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 the following:1.Install core plate wedges, or, 2.Complete a plant-specific analysis to determine acceptance criteria for continued inspection 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 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 year s 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 applicant committed (Commitment #2), to inspect 15 percent of the top guide locations using 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 of Commitments #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).
Conclusion. On the basis of its audit and review of the applicant's BWR Vessel Internals 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 #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 3-63 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 supplement dated 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 primary reactor containment and systems and component s 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 of consistency 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 Report program element "monitoring and trending."
Specifically, the exception states:
The first Type A test after the April 1995 Type A test shall be performed no later than April 2010. This is a one-time extension of the NEI 94-01, 10-year Type A
 
test interval to 15 years. NRC appr oved 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.
The staff reviewed Amendment 227 to Facility Operating License DPR-28 for VYNPS, which extends 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.
3-64 Exception 2. In the supplement to LRA Section B.1.8, the applicant stated an exception to the
>GALL Report program element "acceptance criter ia." Specifically, the exception states:
Main steam leakage pathway contributions (leakage through all four main steam lines 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 license DPR-28 allowing this exemption from the requirements of Sections III.A and III.B of 10 CFR 50
 
appendix 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 License Renewal 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 leakage testing 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 operating experience program that monitors industr y 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 Progr am 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'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 ex perience" 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.
3-65 UFSAR Supplement. In LRA Section A.2.1.8, the applicant provided the UFSAR supplement for the 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 Rate 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 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 supplement dated 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 fuel systems. Exposure to such fuel oil contam inants 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 of consistency 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
 
Diesel Fuel Monitoring Program acceptable because it conformed to the recommended GALL AMP XI.M30, "Fuel Oil Chemistry," with exceptions and enhancements.
3-66 Exception 1. In LRA Section B.1.9, the applicant stated an exception to the GALL Report program elements "scope of program" and "acceptanc e criteria." Specifically, the exception states: The guidelines of ASTM Standard D6217 are not used along with those of D2276 for determination of particulates.
The applicant also stated, in the LRA, that the program uses only the guidance provided in 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 technical
 
specifications.
The staff finds that the applicant is using one of the methods (ASTM D2276) which is recommended 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 ASTM standards 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 program element "preventive actions." Spec ifically, 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, or corrosion inhibitors to the diesel fuel. Plant-specific operating experience has not indicated
 
significant problems related to microbiologically-influenced corrosion. Since water contamination
 
in 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 from the 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 and breakdown of the diesel fuel have not been issues that necessitated the use of fuel additives.
 
Furthermore, the Diesel Fuel Monitoring Program provides for routine monitoring of the diesel
 
fuel 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.
3-67 Exception 3
. In LRA Section B.1.9, the applicant stated exception to the GALL Report program elements "parameters monitored/inspected" and "acc eptance 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 for determination 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 the water 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 be
 
appropriate 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 Report program elements "parameters monitored/inspect ed" and "acceptance criteria." Specifically, the exception states:
Determination of particulates may be according to ASTM Standard D2276, rather than modified ASTM D2276 Method A.
The applicant also stated, in the LRA, that the determination of particulates is based on ASTM 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 the presence 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 following enhancement in meeting the program element "det ection of aging effects." Specifically, the enhancement states:
Ultrasonic thickness measurement of the fuel oil storage and fire pump diesel storage (day) tank bottom surfaces will be performed every 10 years during tank
 
cleaning and inspection.
3-68 The staff determines that the monthly testing of the diesel fuel quality and for the presence of water 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 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 2. In the supplement to LRA Section B.1.9, the applicant stated the following enhancement in meeting the program element "acceptance criteria." Specifically, the enhancement stated:
UT measurements of fuel oil storage and fire pump diesel storage (day) tank bottom surfaces will have acceptance criterion  60 percent Tnom.
The applicant also stated, in the LRA, that for the ultrasonic measurements of the diesel fuel storage 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 of the 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 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 3. In the supplement to LRA Section B.1.9, the applicant stated the following enhancement in meeting the program element "par ameters monitored/inspected." Specifically, the enhancement stated:
Fuel oil in the fire pump diesel storage (day) tank will be analyzed according to ASTM D975-02 and for particulates per ASTM D2276.
The staff reviewed the enhancement and its evaluation is documented in the VYNPS - NRC License 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 Moni toring Program," will be consistent withGALL AMP XI.M30 and will provide additional assurance that the effects of aging will be
 
adequately managed.Enhancement 4. In the supplement to LRA Section B.1.9, the applicant stated the following enhancement in meeting the program element "par ameters monitored/inspected." Specifically, the enhancement stated:
3-69 Fuel oil in the john Deere diesel storage tank will be analyzed for particulates per ASTM D2276.
The staff reviewed the enhancement and its evaluation is documented in the VYNPS - NRC License 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 Moni toring Program," will be consistent withGALL 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 following enhancement in meeting the program element "par ameters monitored/inspected." Specifically, the enhancement stated:
Fuel oil in the common portable fuel oil storage tank will be analyzed according to ASTM 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 - NRC License 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 Monito ring Program," will be consistent with GALLAMP 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 storage
 
tank prove that the program is effective in prev enting loss of material and cracking of fuel system components. QA surveillance in 1999 found an iss ue 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 the LRA. 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 the 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'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 3-70 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 ex perience" 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.2.1.9, the applicant provided the UFSAR supplement for the Diesel Fuel Monitoring Program.
The applicant committed (Commitment #3) to implement the enhancement to the Diesel Fuel Monitoring Program to ensure ultrasonic thickne ss 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 measurem ents 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 of Commitments #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 Monitoring Program, 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).
3.0.3.2.10  Fatigue Monitoring Program
 
Summary of Technical Information in the Application. LRA Section B.1.11 describes the existing Fatigue 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 for selected reactor coolant system components so they do not exceed design limit on fatigue 3-71 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 of consistency 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 Report program element "preventive actions." S pecifically, the exception states that:
The Fatigue Monitoring Program only involves tracking the number of transient cycles 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 include assessment of the impact of reactor water env ironment 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 Report program element "detection of aging effects."
Specifically, the exception states that:
The VYNPS program does not provide for periodic update of the fatigue usage calculations.
The applicant further stated that the VYNPS program provides for periodic assessment of the number 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 periodic review 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.
3-72Enhancement 1. In LRA Section B.1.11, the applicant stated the following enhancement in meeting the program element "detection of agi ng effects." Specifically, the enhancement stated:
The VYNPS program will be modified to either require 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.
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 in meeting the program element "monitoring and tr ending." Specifically, the enhancement states:
A computerized monitoring program (e.g., FatiguePro) will be used to directly determine CUFs for locations of interest.
The staff reviewed a sample of CUF calculations and associated reports and VYNPS technical personnel 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 this enhancement 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 in meeting the program element "acceptance crit eria." Specifically, the enhancement stated:
The allowable number of effective transients will be established for monitored transients. This will allow quantitative projection of future margin.
The staff finds this enhancement acceptable since 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.
Operating Experience. In LRA Section B.1.11, the applicant stated that the condition reporting process documented the discovery of a prev iously 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 def iciencies and tracks corrective actions when necessary. For recent reactor shutdowns and startups, cycle limitations did not trend toward
 
exceeding the allowable number of cycles. Thi s operating experience demonstrates that the program continues to monitor plant transients and to track the accumulation of these transients.
3-73 The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical 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, w ill 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 for the Fatigue Monitoring Program.
The applicant committed (Commitment #5) to modified modify the Fatigue Monitoring Program to
>require 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 establish ed the allowable number of effective
>transients 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 of Commitments #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 ex perience" 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.
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 implement ation of the enhancements (Commitments #5,#6, and #7) 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).
3.0.3.2.11  Fire Protection Program
 
Summary of Technical Information in the Application. In LRA Section B.1.12.1, the applicant stated that "Fire Protection Program," is an existing plant program that is consistent with GALL AMP XI.M26, "Fire Protection," with exceptions and enhancements.
3-74 The Fire Protection Program includes a fire barrier inspection and a 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. 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 of consistency 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 visual indications (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 allow cracks 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 of penetration 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
 
applicant responded that its qualification program was being developed and will include
 
acceptance 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 and testing. 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.
3-75 Exception 1. In LRA Section B.1.12.1, the applicant stated an exception to the GALL Report program element "scope of program." Spec ifically, the exception states that:
This program is not necessary to manage aging effects for halon fire protection system 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 Walkdown Program.The staff asked the applicant to explain statem ent 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 VYNPS will 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 of license 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 suppression system. The applicant responded that the CO 2 fire suppression system had historically been placed 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 reviewed the 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 periodic
 
formal 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 every six months. In its letter, dated March 23, 2007, the applicant revised its LRA to include
 
functional testing of the CO 2 system in accordance with Tec hnical Requirements Manual (TRM) 4.13.D surveillance requirements.
The staff reviewed the applicant's response and concludes that there is no halon fire suppression 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 System Walkdown 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 Report program element "detection of aging." Specifically, the exception states that:
The GALL Report program stated that 10 percent of each type of penetration seal should be visually inspected at least once every refueling outage. The VYNPS
 
program specifies inspection of approximately 25 percent of the seals (regardless 3-76 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 ar e 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 the penetration 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 inaccessible
 
penetration seals. Thus, inaccessible seals would not necessarily be included in any inspection
 
expansion, 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 to consider 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 deter mined that overall it meets or exceeds the penetration 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
 
extended operation. The staff is adequately assured that the fire barrier penetration seals will be
 
considered 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 in meeting the program elements "parameters m onitored/inspected" and "acceptance criteria."
Specifically, the enhancement states:
Procedures will be enhanced to specify that fire damper frames in fire barriers shall 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 applicant responded 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 3-77 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 the issue 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 in meeting the program elements "parameters m onitored/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 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 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
 
applicant added that the fuel condition is monitor ed 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 the enhancement is implemented the "Fire Protecti on Program," will be consistent with GALLAMP 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 condition reports 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 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 3-78 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'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 ex perience" 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.2.1.12, the applicant provided the UFSAR supplement for the Fire Protection Program.
The applicant committed (Commitment #8) to enhance the procedures for the Fire Protection Program 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 Protection Program to state that the diesel engine subsys tems (including the fuel supply line) shall be observed 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.
The 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 of Commitments #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, the staff 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).
3-79 3.0.3.2.12  Fire Water System Program Summary of Technical Information in the Application. LRA Section B.1.12.2 describes the existing Fire Water System Program as c onsistent, with exception and enhancements, withGALL 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. M any 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 of consistency 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 acceptable 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 Report program element "detection of aging effects."
Specifically, the exception states that:
NUREG-1801 specifies annual fire hydrant hose hydrostatic tests. In accordance with 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 asked whether 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 hose test, inspections, and replacement, consistent with its TRM, the staff finds this acceptable.
3-80 Exception 2. In LRA Section B.1.12.2, the applicant stated an exception to the GALL Report program element "detection of aging effects."
Specifically, the exception states that:
NUREG-1801 specifies annual gasket inspections. In accordance with the VYNPS 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 aging effects 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 gasket inspection 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 Report program element "detection of aging effects."
Specifically, the exception states that:
NUREG-1801specifies annual fire hydrant flow tests. In accordance with the VYNPS program, verification of operability and of no flow blockage occurs at least
 
once every three years.
The 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 flow tests 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 Report program 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 typica lly 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 from once 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 3-81 (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 in meeting the program element "detection of agi ng effects." Specifically, the enhancement stated:
A sample of sprinkler heads will be inspected using guidance of NFPA 25 (2002 Edition) 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 provide additional 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 Wa ter System Program, will be consistent withGALL AMP XI.M27 and will provide additional assurance that the effects of aging will be
 
adequately managed.Enhancement 2. In LRA Section B.1.12.2, the applicant stated the following enhancement in meeting the program element "detection of aging effects." Specifically, the enhancement states:
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. 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 would provide 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 the recommendations of the GALL Report. On this basis, the staff finds this enhancement
 
acceptable since when the enhancement is implem ented, "Fire Water System Program," will be 1NFPA 25 requires that sprinkler heads be replaced or representative samples from one or more sample areas be submitted to a recognized testing laboratory for field services testing. In the VYNPS program a representative sample of sprinkler heads will be submitted to a recognized testing laboratory for services testing. The Staff notes that the VYNPS sprinkler heads inspection program appears to elimi nate the option to just replace asprinkler head after 50 years service unless it first undergoes laboratory testing. This imp lies 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.
3-82consistent 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 were verified 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 operating experience program that monitors industr y 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.
The staff reviewed the operating experience provided in the LRA, and interviewed the 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 ex perience" 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.2.1.13, the applicant provided the UFSAR supplement for the Fire Water System Program.
The applicant committed (Commitment #10) to implement the enhancement to the Fire Water System 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 Water System Program to specify that wall thickne ss evaluations of fire protection piping will be performed on system components using non-intrusiv e techniques (e.g., volumetric testing) to 3-83 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 specify annual fire hydrant gasket inspections and flow tests by March 21, 2012.
The applicant committed (Commitment #49) to revise the Fire Water System Program to specify that 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).
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 existing Oil Analysis Program as consistent, with exception, with GALL AMP XI.M39, "Lubricating Oil Analysis."
The Oil Analysis Program maintains oil system s free of contaminants (primarily water and particulates), 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 of consistency 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 whic h preserves an environment that is not conducive 3-84 to loss of material, cracking or fouling. The staff finds the applicant's Oil Analysis Programacceptable 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 Report program 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, total acid/base (neutralization number), water content, and metals content are performed on the
 
sampled oil, but the flash point of the oil is not determined.
The applicant indicated that extensive testing and analyses is performed on all of the sampled oil to 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 oil analysis 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 environm ent 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 the Quality 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'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.
3-85 The staff confirmed that the "operating ex perience" 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.2.1.22, the applicant provided the UFSAR supplement for the 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).
Conclusion. On the basis of its audit and review of the applicant's Oil Analysis 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 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 existing Reactor 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 of consistency 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 material
 
due 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 to the 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 Report program element "detection of aging effects." Specifically, the exception states that:
When reactor head closure studs are removed for examination, either a surface or volumetric examination is allowed.
3-86 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 XI Code Case N-652 which allows surface examination to be substituted for volumetric examination
 
when bolting is removed for examination. Code Case N-652 has been endorsed by the NRC per
 
Table 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 and ultrasonic 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'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 ex perience" 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.2.1.25, the applicant provided the UFSAR supplement for the 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 Studs 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 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).
3-87 3.0.3.2.15  Reactor Vessel Surveillance Program Summary of Technical Information in the Application. LRA Section B.1.24 describes the existing Reactor 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 to maintain 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. Thi s 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-tem perature 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, and
 
contingencies 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 of consistency 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 to manage 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
 
applicant stated in the Reactor Vessel Surveillance Program, and in the Updated Final Safety
 
Analysis 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 3-88 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 to the 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 VYNPS with 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 it would update UFSAR Supplement Section A.2.1.26 and the Reactor Vessel Surveillance
 
Program to include the aforementioned commitm ent (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 approved by 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 to include 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, the capsule 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 it would 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 of aging 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).
Operating Experience. LRA Section B.1.24 states that the applicant participates in the BWRVIP ISP 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.
3-89 The staff confirmed that the "operating ex perience" program element satisfies the recommendation 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 an existing 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-approv ed 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 at VYNPS 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.2.1.26 and 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 that changes 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. Any changes 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 abov e 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).
Conclusion. On the basis of its audit and review of the applicant's Reactor Vessel Surveillance 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 #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 3-90 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 supplement dated March 23, 2007, describes the existing Service Water Integrity Program as consistent, with exceptions and an enhancement, with GALL AMP X I.M20, "Open-Cycle Cooling Water System."
This program implements the recommendations of GL 89-13 to manage aging effects on the service 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 of consistency 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 Wa ter System," with exceptions.
Exception 1. In LRA Section B.1.26, the applicant stated an exception to the GALL Report program element "preventive actions." S pecifically, 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 of appropriate materials and lined or coated to protect the underlying metal surfaces from being
 
exposed to aggressive cooling water environment
: s. Not all VYNPS system components are lined or 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) material and 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 3-91 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 not internally 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 in accordance 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 Report program element "monitoring and trending." Spec ifically, the exception states that:
The GALL Report stated that testing and inspections are performed annually and during refueling outages. The VYNPS program requires tests and inspections
 
each refueling outage.
The applicant noted that the GALL Report program entails testing and inspections performed annually and during refueling outages. The VYNPS program requires tests and inspections each
 
refueling outage, but not annually. Since aging effe cts are typically manifested over several years, the difference in inspection and testing frequency is insignificant.
The applicant stated, in the LRA, that its Service Water Integrity Program requires tests and inspections 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 to inspect 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.
3-92Enhancement. In the LRA supplement dated March 23, 2007, the applicant stated the following enhancement in meeting the GALL Report program el ement "scope of program." Specifically, the enhancement stated:
Enhance the Service Water Integrity Program to require a periodic visual inspection 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 - NRC License 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 inspection results (2004) prove that the program is e ffective 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 be
 
replaced 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 had performed 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
 
20 SWS leaks. During the audit and review discussions/interviews, the applicant stated that no
 
biocides 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 improv ed performance by VYNPS in managing the aging effects 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 3-93 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'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 ex perience" 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.2.1.28, the applicant provided the UFSAR supplement for the Service Water Integrity Program.
The applicant committed (Commitment #45) to implement the enhancement to the Service Water 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 Integrity 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, 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
 
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).
3.0.3.2.17  Structures Monitoring Program
 
Summary of Technical Information in the Application. LRA Section B.1.27.2 describes the existing 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 in RG  1.160 and NUMARC 93-01. These two doc uments provide guidance for development of applicant-specific programs to monitor the condition of structures and structural components 3-94 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 of consistency 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 Maint enance 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 and a 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 site dewatering 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 s eptic 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.
In a letter dated July 14, 2006, the applicant stated by amendment to the application that LRA Section 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. The applicant 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 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.
3-95 The staff also asked the applicant to explain if VYNPS will take advantage of inspection opportunities for structures required for license renewal and identified as inaccessible.
The applicant stated that VYNPS will take advantage of inspection opportunities for underground structures 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 Structures Monitoring 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 plant procedure, 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 and conditions:
* Concrete components: spalling, cracking, delamination, honey combs, water in-leakage, chemical leaching, peeling paint, or discoloration
* Structure Settlement: excessive total or differential settlement
* Structural/seismic gap: insufficient space for structural movement during a seismic event (i.e., exclusion of foreign objects or debris); deteriorated elastomer type
 
filler. 3)ACI 349.3R-96 Chapter 5 provides acc eptable limits beyond which further evaluation is required. PP 7030 Section 4.8 conservatively requires evaluation of identified
 
degradation.
Based upon this comparison, the applicant concluded that the guidance for inspections provided in PP 7030 is consistent with the guidelines in ACI 349.3R-96.
The acceptance criteria for crane rail/girder inspections are contained in the preventive maintenance tasks for the crane inspection. A plant procedure provides the inspection and 3-96 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 applicant has 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 to VYNPS 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 no preventive actions.3)Parameters Monitored - The AERM for concrete structural components 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.
3-974)Detection of Aging - GALL AMP XI.S7 identifies visual inspection methods 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 in RG 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 administrative control attributes of the Structures Monitoring Program and the GALL AMP XI.S7 program are consistent.10)Operating Experience - The operating experience relevant to the effectiveness 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
 
operation. The staff finds the applicant's Structures Monitoring Program acceptable because it conformed 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 in meeting the program element "scope of progr am." Specifically, the enhancement states:
The Structures Monitoring Program will be enhanced to specify that process facility crane rails and girders, condensate storage tank (CST) enclosure, CO 2 tank enclosure, N 2 tank enclosure and restraining wall, CST pipe trench, diesel generator cable trench, fuel oil pump house, SW pipe trench, drywell floor liner 3-98 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 removed the 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 Monitoring Program 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 the enhancement is implemented, the Structures Moni toring Program will be consistent with GALLAMP 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 in meeting the program element "detection of aging effects." Specifically, the enhancement states:
Guidance for performing structural examinations of wood to identify loss of material, 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 the enhancement is implemented, the Structures Moni toring Program will be consistent with GALLAMP 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 in meeting the program element "detection of aging effects." Specifically, the enhancement states:
Guidance for performing structural examinations of elastomers (Drywell floor liner seal, seals, and gaskets) to identify cracking and change in material properties (cracking when manually flexed) will be enhanced in the Structures Monitoring
 
Program procedure.
On this basis, the staff finds this enhancement (Commitment #22) acceptable since when the enhancement is implemented, the Structures Moni toring Program will be consistent with GALLAMP 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 in meeting the program element "detection of aging effects." Specifically, the enhancement states:
3-99 Guidance for performing structural examinations of PVC cooling tower fill to identify 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 the enhancement is implemented, Structures Monito ring Program," will be consistent with GALLAMP 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 Deere diesel 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 t he 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 signific ant findings during these inspections proves that the program is effective for managing loss of material, cracking, and change in material
 
properties for structural components.
The staff reviewed the summary of specific operating experience for the Structures Monitoring Program. 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 identifyi ng age-related degradation, implementing repairs, and maintaining the structural integrity of the structures and associated components within the scope
 
of license renewal.
3-100 The staff also reviewed the 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. 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 ex perience" 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.2.1.30, the applicant provided the UFSAR supplement for the Structures Monitoring Program.
The applicant committed (Commitment #20) to enhance the Structures Monitoring Program to specify that process facility crane rails and girders, CST enclosure, CO 2 tank enclosure, N 2 tank enclosure 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 to add 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 to add 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 to add guidance for performing structural examinations of PVC cooling tower fill to identify cracking
 
and change in material properties by March 21, 2012.
The applicant committed (Commitment #33) to include in the Structures Monitoring Program provisions 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 Monitoring 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 #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 3-101 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 the existing 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 fouling for 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 monito r and control CCW chemistry using plant-specific procedures and processes based on EPRI guidance for CCW chemistry.
Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency 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 Water Programfor 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
* Augmented Off-Gas Refrigerant Skid Water and Chilled Water
* Emergency Diesel Generator Closed Cooling Water
* Turbine Building Closed Cooling Water The staff finds the applicant's Water Chemistry Control-Closed Cooling Water Program acceptable 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 Report program element "detection of aging effects."
Specifically, the exception states that:
The VYNPS Water Chemistry Control-Closed Cooling Water Program does not include performance and functional testing.
Exception Note
. While GALL AMP XI.M21, Closed-Cycle Cooling Water System endorses 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 3-102 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 applicant stated 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, thermowe lls, and valve bodies in the various systems, would be selected.
The staff determines 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.
Operating Experience. LRA Section B.1.30.3 states that monthly sample results from January 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
 
molybdate corrosion inhibitor was within the EPRI action Level 1 range; the reading was slightly
 
low, 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 were resolved 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 administrat ive 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 implementati on 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'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 3-103 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 ex perience" 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.2.1.36, the applicant provided the UFSAR supplement for the 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 LRA to 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 Chemistry Control-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
 
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).
3.0.3.2.19  Bolting Integrity Program
 
Summary of Technical Information in the Application. In a letter dated October 17, 2006, the applicant 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 of safety-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 bolting integrity 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.
3-104 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 and
 
maintenance, 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 torquing practices 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.
Staff Evaluation. During its audit and review, 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 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 selecting materials for low susceptibility to SCC.
The staff finds that this enhancement ensures that the recommendations in the referenced documents are properly implemented. On this bas is, the staff finds this enhancement acceptable since when the enhancement is implemented, the Bolting Integrity Program will be consistentwith 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 identify cracking 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 3-105 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 provi ded in the LRA supplement and interviewed the 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 ex perience" 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. The applicant provided the UFSAR supplement for the Bolting Integrity Program.The applicant committed (Commitment #34) to implement the Bolting Integrity Program by March 21, 2012.
The staff reviewed the UFSAR Supplement section and determines that, upon implementation of Commitment #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, the staff 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 implement ation 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, the applicant 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, internal portions 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, 3-106 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.
Exception 1. In the revised LRA Section B.1.32, the applicant stated an exception to the GALL Report 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 internal surfaces. The applicant also stated that, in accordance with Exception Note 1, that inspection of
 
MEB 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 GALL Report 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 which runs 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 that since 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 Bus Inspection Program is a new program. The pr ogram is based on the program described in 3-107 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 at VYNPS is controlled by procedure. The program includes the following components: (1)
 
Operating Experience - Information received fr om 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 (O E) 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 exper ience 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.
The staff reviewed the operating experience provided in the revised 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. 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 UFSAR supplement for the Meta-Enclosed Bus Inspection Program.
The applicant committed (Commitment #32) to implement the Metal-Enclosed Bus Program by March 21, 2012.
The staff reviewed LRA Section A.2.1.38 and determines that, upon implementation Commitment
#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 Bus Inspection 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 Report In LRA Appendix B, the applicant identified the following AMPs as plant-specific:
3-108
* 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 Program For AMPs not consistent with or not addressed in the GALL Report, the staff performed a complete 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.
3.0.3.3.1  Heat Exchanger Monitoring Program
 
Summary of Technical Information in the Application. LRA Section B.1.14 describes the Heat Exchanger Monitoring Program as a new, plant-specific program.
The Heat Exchanger Monitoring Program will inspect heat exchangers for degradation and, if found, 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 oil
 
cooler, 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 pr ior to the period of extended operation.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA 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 Monito ring Program against the AMP 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 effectiv e incorporation of 10 elements (i.e., "scope of the program," "preventive actions," "paramet ers monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance criteria," "corrective actions," "confirmation
 
process," "administrative controls," and "operating experience").
The applicant indicated that the "corrective actions," "confirmation process," and "administrative controls" program elements are parts of the si te-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 aging effects on selected heat exchangers in various systems as identified in AMRs. In the 3-109 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 aging effects 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 the recommendation 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.1.14 states that this program is an inspection program and no actions are taken as part of this program to prevent degradation.
The staff confirmed that the preventive acti ons program element satisfied the criteria defined 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 the recommendation 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 where practical, 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 acti ons program element satisfied the criteria defined 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 element satisfies 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 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 3-110 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 appropriate sample 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 exc hanger (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.
The LRA supplement also stated that testing frequency will be established using baseline eddy 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 thi ckness 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 heat exchangers 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 pressure boundary 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 the recommendation 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 be evaluated 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 the criteria 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 3-111 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 satisfies recommendation 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.  (6)Acceptance Criteria - LRA Section B.1.14 states that the minimum acceptable tube wall thickness 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 heat exchanger 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 criter ia program element satisfied the criteria defined 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 the recommendation 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 experience for the new Heat Exchanger Monitoring Program.
The staff recognized 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 ex perience" program element satisfies the recommendation 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 for the Heat Exchanger Monitoring Program.
The applicant committed to implement the Heat Exchanger Monitoring Program, documented as Commitment #12, as described in VYNPS AMP B.1.14, by March 21, 2012.
3-112 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 Monitoring Program 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
 
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).
3.0.3.3.2  Containment Inservice Inspection Program
 
Summary of Technical Information in the Application. LRA Section B.1.15.1 describes the Containment 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 exam inations 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 Progr am encompasses the requirements for the inspection 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 in LRA 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 elements finds 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").
3-113 During the audit and review, the staff asked the applicant to explain why its Containment Inservice Inspection Program was a plant-specif ic program instead of an existing plant programthat 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 generat ed many exceptions and explanations which would have detracted from the objective of the comparison. Therefore, the Inservice Inspection -
 
Containment Inservice Inspection Program was pr esented 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 of the 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 sy stem. 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 aging effects 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 the recommendation 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 monitoring program that does not include preventive actions.
The staff confirmed that the preventive acti ons program element satisfied the criteria defined 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 w ill not perform any preventive or mitigating action for aging effects/mechanisms. On this basis, the staff finds the applicant's
 
preventive actions acceptable.
3-114 The staff confirmed that the "preventive actions" program element satisfies the recommendation 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 primary containment and its attachments are inspected for evidence of cracks, wear, and
 
corrosion.
The staff asked the applicant to explain why VYNPS did not have a Service Level I Protective 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 impai r 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 Sy stem 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 that the 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 moni tored/inspected program element satisfies the 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 of
 
surface 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 element satisfies 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.
3-115  (4)Detection of Aging Effects - LRA Section B.1.15.1 states that this program manages loss of 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 or remotely 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-LR Appendix 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 the recommendation 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 are compared, as appropriate, to baseline data and other previous test results. If indications
 
are accepted for continued use by analytical evaluation, the areas containing such flaws
 
are monitored during successive inspection periods.
The staff confirmed that for visual inspection, this program element satisfies the criteria defined 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 the recommendation in the GALL Report and the criterion defined in SRP-LR
 
Appendix A.1.2.3.5. The staff finds this program element acceptable.
3-116  (6)Acceptance Criteria - LRA Section B.1.15.1 states that program results are compared, as appropriate, 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 criter ia program element satisfied the criteria defined 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 the recommendation 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 Program associated 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 it satisfied 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 ex ist, 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 Program 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 it satisfied 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.
3-117  (9)Administrative Controls - The adequacy of the applicant's 10 CFR 50, Appendix B Program 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 it satisfied the criteria defined in SRP-LR Appendix A.1.2.3.9. The staff finds that the
 
applicant's Containment Inservice Inspecti on 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 only two 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 effe ctive at managing aging effects for primary containment and its integral attachments.
Further, QA surveillance during RFO 24 reveal ed a problem with program administrative controls. 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. Reso lution 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.
3-118 The staff reviewed the summary of specific operating experience provided in the applicant'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 a result 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 a deficiency 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 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 ex perience" 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.2.1.16, the applicant provided the UFSAR supplement for the 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).
3-119 Conclusion. On the basis of its technical review of the applicant's Containment 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).
3.0.3.3.3  Inservice Inspection Program
 
Summary of Technical Information in the Application. LRA Section B.1.15.2 describes the Inservice Inspection Program, as an existing, plant-specific program.Section 50.55a of 10 CFR imposes inservice inspection requirements of ASME Code Section XI for 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 ofASME 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, ul trasonic, or eddy current examinations to locate surface and subsurface flaws. Surface exami nations 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-y ear 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 in LRA 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.
The staff reviewed the Inservice Inspection Program against the AMP 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 effectiv e incorporation of 10 elements (i.e., "scope of the program," "preventive actions," "parameter s monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance criteria," "corrective actions," "confirmation
 
process," "administrative controls," and "operating experience").
3-120 The applicant indicated that the "corrective actions," "confirmation process," and "administrative controls" program elements are parts of the si te-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 impl ements applicable requirements of ASMECode, 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 aging effects 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 the recommendation 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 condition monitoring program that does not include preventive actions.
The staff confirmed that the preventive acti ons program element satisfies the criteria defined 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 the recommendation 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.1.15.2 states that this program uses NDE 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-1 visual 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 3-121 using various optical and video devices. VT-2 vi sual examination is conducted specifically to 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 visual
 
examination 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 acti ons program element satisfied the criteria defined 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 element satisfies 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 manages cracking 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 in ASME Code, Section XI, Subsection IWB examination categories.
The applicant also stated that its Inservice Inspection Program manages cracking, loss of preload, 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 of material 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.
The staff confirmed that this program element satisfies the criteria defined in SRP-LR Appendix 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 the recommendation in the GALL Report and the criterion defined in SRP-LR
 
Appendix A.1.2.3.4. The staff finds this program element acceptable.
3-122  (5)Monitoring and Trending - LRA Section B.1.15.2 states that program results are compared, as appropriate, to baseline data and, other previous test results. If indications
 
are accepted for continued use by analytical evaluation, the areas containing such flaws
 
are monitored during successive inspection periods.
The applicant also stated that ISI results are recorded every operating cycle and provided to 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 the criteria 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 the recommendation 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, or baseline, 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 criter ia program element satisfied the criteria defined 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.
The staff confirmed that the "acceptance criteria" program element satisfies the recommendation 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 pressure boundary 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 3-123 inspections from 2001 to 2004 revealed no issues or findings that could impact programeffectiveness.
The staff reviewed the 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. 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 ex perience" 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 for the 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).
3.0.3.3.4  Instrument Air Quality Program
 
Summary of Technical Information in the Application. LRA Section B.1.16 describes the Instrument Air Quality Program as an existing, plant-specific program.
The Instrument Air Quality Program maintains instrument air (IA) supplied to components free of water 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 in LRA 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 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 effectiv e incorporation of 10 elements (i.e., "scope of the program," "preventive actions," "parameter s monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance criteria," "corrective actions," "confirmation
 
process," "administrative controls," and "operating experience").
3-124 The applicant indicated that the "corrective actions," "confirmation process," and "administrative controls" program elements are parts of the si te-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 components within 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 aging effects 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 the recommendation 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 and maintained within specified limits to ensure that IA supplied to components is maintained
 
free of water and significant contaminants, thereby preventing loss of material.
The staff confirmed that the preventive acti ons program element satisfies the criteria defined 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 the recommendation 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, particulate contamination and hydrocarbon concentration are periodically checked to verify IA quality is maintained.
The staff confirmed that the preventive acti ons program element satisfied the criteria defined 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.
3-125 The staff confirmed that the "parameters monitored or inspected" program element satisfies 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, particulate contamination 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 the criteria 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 the recommendation 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.1.16 states that results of sample analyses are maintained 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 program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.5. Effects of corrosion
 
and the presence of contaminants are monitor ed 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 the recommendation 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 criter ia program element satisfied the criteria defined 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.
3-126 The staff confirmed that the "acceptance criteria" program element satisfies the recommendation 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 all parameters 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 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 ex perience" 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.2.1.18, the applicant provided the UFSAR supplement for the 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 Program with 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 Periodic Surveillance and Preventive Maintenance Program as an existing, plant-specific program.
The Periodic Surveillance and Preventive Maintenance Program includes periodic inspections and tests that manage aging effects not managed by other AMPs. Preventive maintenance and surveillance testing are generally implemented th rough 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 structur es, HPCI system, standby gas treatment system (SGTS), primary containment atmosphere cont rol (PCAC) system, SWS, EDG system, HVAC 3-127 system, John Deere diesel, and nonsafety-related systems and components affectingsafety-related systems.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA 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 the AMP 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 t he program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance
 
criteria," "corrective actions," "confirmation pr ocess," "administrative controls," and "operating experience").
The applicant indicated that the "corrective actions," "confirmation process," and "administrative controls" program elements are parts of the si te-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 license renewal, includes those tasks credited with managing aging effects identified in AMRs.
The staff confirmed that the specific components for which the program manages aging effects 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 the recommendnation 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 used to 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 acti ons program element satisfies the criteria defined 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 the recommendation 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 program provides instructions for monitoring st ructures, systems, and components to detect degradation. Inspection and testing activities monitor various parameters including 3-128 system flow, system pressure, surface condi tion, loss of material, presence of corrosion products, and signs of cracking.
The staff reviewed the applicant's basis document and compared with AMRs which credit Periodic Surveillance and Preventive Maintenance Program and concurred with the
 
applicant that inspection and testing activities monitor various parameters including
 
system flow, system pressure, surface condi tion, 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 element satisfies 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.1.22 states that 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. 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 provides inspection intervals and inspection method. The staff finds that periodic surveillance
 
intervals and requirements meet TS require ments 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 interval of 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.
3-129 The staff reviewed the information provided by the applicant. On the basis of its review of the 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-LR Appendix 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 satisfies therecommendnation 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.1.22 states that preventive maintenance and surveillance 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 and determines 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 the recommendation 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 criteria are 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 (primary containment surveillance, secondary containm ent 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 the applicant's acceptance criteria were clearly defined in its operating procedures. For
 
example, the staff reviewed applicant's procedures, as documented in the Audit and 3-130 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 the recommendation 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 to 2004) 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;
 
John Deere diesel exhaust gas components had no significant corrosion or cracking; and
 
ECCS corner room recirculation units had no significant corrosion). QA audits and
 
surveillances, 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 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 ex perience" 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.2.1.24, the applicant provided the UFSAR supplement for the Periodic Surveillance and Preventive Maintenance Program.
The applicant committed ( Commitment #17) to enhance the Periodic Surveillance and Preventive Maintenance 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 and Preventive 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 3-131 this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.3.6  Vernon Dam FERC Inspection
 
Summary of Technical Information in the Application. LRA Section B.1.27.3 and LRA supplement dated 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) inspection program. This program consists of visual inspections in accordance with FERC guidelines and
 
complies with Tittle 18 of the Code of Federal Regulations (CFR), Conservation of Power and Water 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 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 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 in LRA 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-specific program. 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 recent inspections (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.
3-132 Recent FERC assessment (2002) of the Vernon Dam structures found that SCs are maintained in accordance 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.
In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in LRA Section 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 the listed 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's technical 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 exempted the 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 Vernon Project 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 Energy Regulatory 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 management program 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).
3-133 In letter dated July 3, 2007, the applicant committed (Commitment #50) that during the period of extended operation, at least once every five years, VYNPS will confirm that the Vernon Dam
 
owner is performing the required FERC inspections based on a review of the Vernon Dam
 
owner'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 the owner 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 Water Chemistry Control - Auxiliary Systems Progr am as an existing, plant-specific program.
The purpose of the Water Chemistry Control -
Auxiliary Systems Progr am is to manage aging effects 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 in LRA Section B.1.30.1 on the applicant's demonstration of the Water Chemistry Control - Auxiliary
 
Systems Program to ensure that the effect s 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 Contro l - Auxiliary Systems Program against the AMP 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 t he program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance
 
criteria," "corrective actions," "confirmation pr ocess," "administrative controls," and "operating experience").
The applicant indicated that the "corrective actions," "confirmation process," and "administrative controls" program elements are parts of the si te-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 sampling and analysis of stator cooling water and plant heating boiler systems, and flushing of the
 
John Deere Diesel cooling water system.
3-134 The staff confirmed that the specific components for which the program manages aging effects 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 the recommendnation 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 monitoring and 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 environment s 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 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.
The staff confirmed that the existing chemistr y activities and preventive actions taken by the 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 the recommendation 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 with industry 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 acti ons program element satisfies the criteria defined 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.
3-135 The staff confirmed that the "parameters monitored or inspected" program element satisfies 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 loss of 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 Program describes 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 the criteria 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 the recommenndation 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 analyses are archived for long-term trending and review.
The staff confirmed that this program element satisfies the criteria defined in SRP Section 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 the recommenndation 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 chemistry parameters 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
 
provided in EPRI Report 1007820, "Revision 1 to TR-107396, Closed Cooling Water 3-136 Chemistry Guidelines." On this basis, the staff finds the applicant's acceptance criteria is acceptable.
The staff confirmed that this program element satisfies the criteria defined in SRP-LR Appendix 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 the recommendation 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 house heating boiler sample results in 2004 and 2005 show parameters within acceptance
 
criteria, proving that the program is effe ctive 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 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 ex perience" 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.2.1.34, the applicant provided the UFSAR supplement for the Water Chemistry Control - Auxiliary Systems Program.
In addition, in a letter dated January 14, 2007, the applicant provided an amendment to its LRA to explicitly state, "One-Time Inspection Program,"
activities will confirm the effectiveness of "Water Chemistry Control - Aux iliary Systems Program."
The applicant committed (Commitment #26) to enhance procedures to flush the John Deere Diesel Generator cooling water system and repl ace 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 of Commitments #26, 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 Water Chemistry Control -
Auxiliary Systems Program with the addition of Commitment #26, the staff concludes that the 3-137 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, applicant revised 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 or electrical devices. Connections associated with cables within the scope of license renewal are considered 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 cable
 
connections (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 information included 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 the GALL 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 effectiv e 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 experi ence"). 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 to Non-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.
The staff determines that the specific commodity groups for which the program manages aging effects are identified (Non-environmental qualification bolted cable connections 3-138 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 pr eventive 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 inspection program 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 acti ons program element satisfies the criteria defined 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 this program 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 an
 
issue that requires a periodic AMP.
The staff determines that the parameters monitored/inspected program element satisfies the 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 representative sample 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.
The staff determines that this program element satisfies the criteria defined in SRP-LR Appendix 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.
3-139 Contact resistance measurement is an appropriate inspection technique to detect high resistance of bolted cable connections due to chemical contamination, corrosion, and
 
oxidation. Visual inspection is an alternat ive 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 account
 
for 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 a one-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 criteria for 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-LR Appendix 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 Program 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 it satisfies 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 Program 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 it satisfies 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 3-140 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 B Program 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 it satisfies 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 operating experience 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 Connections Program 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 UFSAR supplement 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 transient s, 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. Connections
 
covered in accordance with the Environmental Qualification program, or connections inspected or
 
tested as part of a preventive maintenance pr ogram are excluded from an AMR. 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. This progr am will be implemented prior to the period of extended operation.
3-141 The staff reviewed the UFSAR supplement, and determines that it provides a adequate summary description 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 applicant has 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 Attribut es Integral to Aging Management Programs Pursuant to 10 CFR 54.21(a)(3), the applicant is required to demonstrate that the effects of aging on 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 Pr ogram for License Renewal," provides the following description of these program elements:(7)Corrective Actions - Corrective actions, including root cause determination and prevention of recurrence, should be timely.(8)Confirmation Process - The confirmation process should ensure that preventive actions are adequate and that appropriate corrective
 
actions have been completed and are effective.(9)Administrative Controls - Administrative controls should provide a formal review and approval process.
Those aspects of the AMP that affect the quality of safety-related SSCs and are subject to the QA requirements of 10 CFR Part 50, Appendix B are noted in SRP-LR, BTP IQMB-1, "Quality
 
Assurance for Aging Management Programs." Addi tionally, 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, conf irmation 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 B requirements which are adequate to address all quality-related
 
aspects of an AMP consistent with the CLB of the facility for the
 
period of extended operation.For nonsafety-related SCs that are subject to an AMR, an applicant has 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, 3-142 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 Application In LRA Sections A.2.1, "Aging Management Programs and Activities," and B.0.3, "VYNPS Corrective 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, confir mation, and administrative controls are applied in 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 each unique component type or commodity group deter mined to require aging management during the period of extended operation.
3.0.4.2  Staff Evaluation Pursuant to 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects of aging on SCs subject to an AMR will be adequately managed so that their intended functions will be
 
maintained consistent with the CLB for the period of extended operation. 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 that appropriate 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 of safety-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
 
10 CFR Part 50 QA program may be used to address the elements of corrective action, 3-143 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 are adequate 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 inconsistencies associated 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 sta ff 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 the 10 CFR Part 50, Appendix B, QA Program for corrective action, confirmation process, and
 
administrative controls, and to supplement the LR A, 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, and January 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 the ENTERGY (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.
With respect to the VHS, the applicant stated, in part, that although the VHS is not under the VYNPS 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 3-144 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 progr am. 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  Conclusion On the basis of the staff's evaluation, the descriptions and applicability of the plant-specific AMPs and 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 Vesse l, Reactor Vessel Internals, and ReactorCoolant System This 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 Application LRA Section 3.1 provides AMR results for the reactor vessel, reactor vessel internals, and reactor coolant 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.
3-145 The applicant's AMRs evaluated and incorporated applicable plant-specific and industry operating 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.
 
====3.1.2 Staff====
Evaluation The staff reviewed LRA Section 3.1 to determine whether the applicant provided sufficient information 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 AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters described
 
in the GALL Report; however, the staff did verify that the material presented in the LRA was
 
applicable and that the applicant 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 which further 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, 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 ensure that they provided an adequate description of the programs credited with managing or monitoring aging for the reactor vessel, internals and reactor coolant system components.
Table 3.1-1 summarizes the staff's evaluation of components, aging effects/mechanisms, and AMPs listed in LRA Section 3.1 and addressed in the GALL Report.
3-146 Table 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 GALLReportAMP in LRAStaff Evaluation Steel pressure vessel 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 and valve 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 GALLReportAMP in LRAStaff Evaluation 3-147Nickel alloy tubes and 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 to BWRs Steel and stainless steel 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 to BWRs 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 to BWRs 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 to BWRs Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-148 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 to BWRs 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
 
corrosion Water 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 3.1.2.1.1
 
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
 
corrosion Water Chemistryand One-Time
 
InspectionNoneNot applicable to BWRs 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 corrosion Water 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 3.1.2.1.2
 
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
 
corrosion Water 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); 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 GALLReportAMP in LRAStaff Evaluation 3-149 Stainless steel; steelwith 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
 
corrosion Water 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
 
corrosion InserviceInspection (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 to BWRsSteel (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
 
embrittlement Reactor Vessel Surveillance Reactor Vessel Surveillance
 
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 to SCC and IGSCC A plant-specific AMP 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 GALLReportAMP in LRAStaff Evaluation 3-150 Stainless steel isolation condenser
 
components
 
exposed to reactor
 
coolant (3.1.1-20)
Cracking due to SCC and IGSCC InserviceInspection (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 to BWRs 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 to BWRs Stainless steel reactor vessel
 
closure head flange
 
leak detection line
 
and bottom-mounted
 
instrument guide
 
tubes (3.1.1-23)
Cracking due to SCC A plant-specific AMP is to be
 
evaluated.NoneNot applicable to BWRs Class 1 CASS piping, piping
 
components, and
 
piping elements
 
exposed to reactor
 
coolant (3.1.1-24)
Cracking due to SCC Water Chemistry and, for CASS
 
components that do
 
not meet the
 
NUREG-0313
 
guidelines, a
 
plant-specific AMPNoneNot applicable to BWRs Stainless steel jet pump sensing line
 
(3.1.1-25)
Cracking due tocyclic loading A plant-specific AMP 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 GALLReportAMP in LRAStaff Evaluation 3-151 Steel and stainless steel isolation
 
condenser components
 
exposed to reactor
 
coolant (3.1.1-26)
Cracking due tocyclic loading InserviceInspection (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 to BWRs Steel steamgenerator FW
 
impingement plate
 
and support
 
exposed to secondary FW
 
(3.1.1-28)
Loss of material due to erosion A plant-specific AMP is to be
 
evaluated.NoneNot applicable to BWRs Stainless steelsteam dryers
 
exposed to reactor
 
coolant (3.1.1-29)
Cracking due toflow-induced
 
vibration A plant-specific AMP 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 GALLReportAMP in LRAStaff Evaluation 3-152 Stainless steel reactor 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
 
SCC Water Chemistryand 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 to BWRsNickel 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 cracking InserviceInspection (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 to BWRs Steel steamgenerator FW inlet
 
ring and supports
 
(3.1.1-32)Wall thinning due toflow-accelerated
 
corrosion A plant-specific AMP is to be
 
evaluated.NoneNot applicable to BWRs Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-153 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 to BWRs Stainless steel andnickel alloy reactor
 
CRD head penetration pressure
 
housings (3.1.1-34)
Cracking due to SCC and primary water stress
 
corrosion cracking InserviceInspection (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 to BWRsSteel 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 to SCC and primary water stress
 
corrosion cracking InserviceInspection (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 to BWRs Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-154Nickel alloy, stainless steel
 
pressurizer spray
 
head (3.1.1-36)
Cracking due to SCC and primary water stress
 
corrosion cracking Water 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 to BWRs 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
 
cracking Water Chemistryand 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 to BWRsSteel (with orwithout stainless
 
steel cladding) CRD
 
return line nozzles
 
exposed to reactor
 
coolant (3.1.1-38)
Cracking due tocyclic loading BWR CR Drive Return Line Nozzle BWR CRD Return Line 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 Feedwater NozzleBWR Feedwater Nozzle 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 GALLReportAMP in LRAStaff Evaluation 3-155 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 Chemistry Water 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 to SCC and IGSCC BWR Stress Corrosion Cracking and Water Chemistry BWR Stress Corrosion 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 to SCC and IGSCC BWR Vessel ID Attachment Welds and Water Chemistry BWR Vessel ID Attachment 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 fuel supports and CRD
 
assemblies CRD
 
housing exposed to
 
reactor coolant
 
(3.1.1-43)
Cracking due to SCC and IGSCC BWR VesselInternals and Water
 
Chemistry BWR 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
 
cracking BWR VesselInternals and Water
 
Chemistry BWR 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 GALLReportAMP in LRAStaff Evaluation 3-156 Steel piping, piping components, and
 
piping elements
 
exposed to reactor
 
coolant (3.1.1-45)Wall thinning due toflow-accelerated
 
corrosionFlow-Accelerated CorrosionFlow-Accelerated Corrosion 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
 
cracking InserviceInspection (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
 
corrosion InserviceInspection (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 stainless steel Class 1 piping, fittings and branch connections < 4
 
inches NPS
 
exposed to reactor
 
coolant (3.1.1-48)
Cracking due to SCC, IGSCC (for stainless steel only),
and thermal and
 
mechanical loading InserviceInspection (IWB, IWC, and IWD),
Water chemistry, and One-Time
 
Inspection of ASME
 
Code Class 1
 
Small-bore Piping Inservice 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
 
cracking InserviceInspection (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 welds BWR 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 to SCC and IGSCC Reactor Head Closure Studs Reactor Head Closure 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 GALLReportAMP in LRAStaff Evaluation 3-157 CASS jet pumpassembly castings;
 
orificed fuel support
 
(3.1.1-51)
Loss of fracture toughness due to
 
thermal aging and
 
neutron irradiation
 
embrittlementThermal Aging and Neutron Irradiation
 
Embrittlement of
 
CASSThermal Aging and Neutron 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 stainless steel 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 to SCC, 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 due to 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 GALLReportAMP in LRAStaff Evaluation 3-158 CASS Class 1 pump casings, and valve
 
bodies and bonnets
 
exposed to reactor coolant > 250C(> 482F)(3.1.1-55)
Loss of fracture toughness due to
 
thermal aging
 
embrittlement Inserviceinspection (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 > 15percent Zn piping, piping components, and piping elements
 
exposed to closed cycle cooling water
 
(3.1.1-56)
Loss of material due to selective leaching Selective Leaching of 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 RCPB external surfaces exposed to air with borated water leakage
 
(3.1.1-58)
Loss of material due to Boric acid
 
corrosionBoric Acid CorrosionNoneNot applicable to BWRs 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-Accelerated CorrosionNoneNot applicable to BWRs Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-159 Stainless steel fluxthimble tubes (with or without chrome
 
plating)
(3.1.1-60)
Loss of material due to WearFlux Thimble Tube InspectionNoneNot applicable to BWRs Stainless steel, steel pressurizer integral
 
support exposed to air with metal
 
temperature up to
 
288C (550F)(3.1.1-61)
Cracking due tocyclic loading InserviceInspection (IWB, IWC, and IWD)NoneNot applicable to BWRs Stainless steel, steelwith 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 loading InserviceInspection (IWB, IWC, and IWD)NoneNot applicable to BWRs Steel 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 due to Wear InserviceInspection (IWB, IWC, and IWD)NoneNot applicable to BWRs Stainless steel andsteel with stainless
 
steel or nickel alloy
 
cladding pressurizer
 
components
 
(3.1.1-64)
Cracking due toSCC, primary water
 
stress corrosion
 
cracking InserviceInspection (IWB, IWC, and IWD) and
 
Water ChemistryNoneNot applicable to BWRs Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-160Nickel alloy reactor vessel 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 cracking InserviceInspection (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 to BWRs 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 erosion InserviceInspection (IWB, IWC, and IWD) for
 
Class 2 componentsNoneNot applicable to BWRsSteel with stainless steel or nickel alloy
 
cladding; or
 
stainless steel
 
pressurizer
 
components
 
exposed to reactor
 
coolant (3.1.1-67)
Cracking due tocyclic loading InserviceInspection (IWB, IWC, and IWD), and
 
Water ChemistryNoneNot applicable to BWRs Stainless steel, steelwith 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 SCC InserviceInspection (IWB, IWC, and IWD), and
 
Water ChemistryNoneNot applicable to BWRs Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-161 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
 
cracking InserviceInspection (IWB, IWC, and IWD), and
 
Water ChemistryNoneNot applicable to BWRs Stainless steel; steelwith stainless steel
 
cladding Class 1
 
piping, fittings and
 
branch connections
< 4 inches
 
NPS exposed to
 
reactor coolant
 
(3.1.1-70)
Cracking due to SCC, thermal and
 
mechanical loading InserviceInspection (IWB, IWC, and IWD),
Water chemistry, and One-Time
 
Inspection of ASME
 
Code Class 1
 
Small-bore PipingNoneNot applicable to BWRs High-strength lowalloy steel closure
 
head stud assembly exposed to air with
 
reactor coolant
 
leakage (3.1.1-71)
Cracking due to SCC; loss of material due to wear Reactor Head Closure StudsNoneNot applicable to BWRsNickel alloy steam generator tubes and
 
sleeves exposed to
 
secondary FW/steam (3.1.1-72)
Cracking due to OD SCC and
 
intergranular attack, loss of material due to fretting and wear Steam GeneratorTube Integrity and
 
Water ChemistryNoneNot applicable to BWRsNickel alloy steam generator tubes, repair sleeves, and
 
tube plugs exposed
 
to reactor coolant
 
(3.1.1-73)
Cracking due toprimary water stress
 
corrosion cracking Steam GeneratorTube Integrity and
 
Water ChemistryNoneNot applicable to BWRs Chrome plated steel, stainless
 
steel, nickel alloy
 
steam generator
 
anti-vibration bars
 
exposed to
 
secondary FW/steam (3.1.1-74)
Cracking due to SCC, loss of
 
material due to
 
crevice corrosion
 
and fretting Steam GeneratorTube Integrity and
 
Water ChemistryNoneNot applicable to BWRs Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-162 Nickel alloy once-through steam
 
generator tubes
 
exposed to
 
secondary FW/steam (3.1.1-75)
Denting due to corrosion of carbon
 
steel tube support
 
plate Steam GeneratorTube Integrity and
 
Water ChemistryNoneNot applicable to BWRs 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
 
corrosion Steam GeneratorTube Integrity and
 
Water ChemistryNoneNot applicable to BWRsNickel 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 corrosion Steam GeneratorTube Integrity and
 
Water ChemistryNoneNot applicable to BWRs Steel steam generator tube
 
support lattice bars
 
exposed to
 
secondary FW/steam (3.1.1-78)Wall thinning due toflow-accelerated
 
corrosion Steam GeneratorTube Integrity and
 
Water ChemistryNoneNot applicable to BWRsNickel alloy steam generator tubes
 
exposed to
 
secondary FW/steam (3.1.1-79)
Denting due to corrosion of steel
 
tube support plate Steam 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 to BWRs Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-163 CASS reactor vessel 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 and Neutron Irradiation
 
Embrittlement of
 
CASSNoneNot applicable to BWRsNickel 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 to BWRs Stainless steel steam generator primary side divider
 
plate exposed to
 
reactor coolant
 
(3.1.1-82)
Cracking due to SCCWater ChemistryNoneNot applicable to BWRs Stainless steel; steelwith 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 to BWRsNickel 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 SCC Water Chemistryand One-Time
 
Inspection or
 
Inservice Inspection (IWB, IWC, and IWD).NoneNot applicable to BWRs Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-164Nickel 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 system component 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 Report Summary 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 3-165
* 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 Steel Program
* Water Chemistry Control - BWR Program
* Water Chemistry Control - Closed Cooling Water Program Staff 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 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 the information 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 consistent with 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.
3-166 Note D indicates that the component for the AMR line item, although different from, is consistent with 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 the system, 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 Water Chemistry Control-BWR Program, augmented by t he 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 Inspection Program 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 applicant included 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.
On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
3-167 The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience
 
and proposals for managing 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 Water Chemistry Control-BWR Program, augmented by t he 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 Inspection Program 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 applicant included 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 aging effect/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 Water Chemistry Control-BWR Program, augmented by t he 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.
During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program 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 Progr am, 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 applicant included all components in LRA Table 3.1.1, Item 3.1.1-14 in the population that is subject to the 3-168 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 aging effect/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 Water Chemistry Control-BWR Program, augmented by t he 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 Inspection Program 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 applicant included 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 aging effect/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 of fracture 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 for materials 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), "Ent ergy Northeast Vermont Yankee Neutron Flux Evaluation," flux variations of up to but less than 19 percent were considered. During the
 
audit 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 19 percent 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.
3-169 In its response, by letter dated September 5, 2006, the applicant stated that a 19 percent uncertainty 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 that the fluence was extrapolated to determine the height at which fluence would equal 1 x10 17 n/cm 2 rather 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 applicant stated 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 of extended operation.
The staff reviewed the GE fluence calculations, GE-NE-000-0007-2342-R1-NP, in conjunction with 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 BWR Vessel 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 if BWRVIP-139 is approved. Exceptions, if any, will be subject to
>review and approval by the staff.
The staff finds that since the applicant committed (Commitment #37) to implement BWRVIP-139
>as approved by the staff , if the staff does approve BWRVIP-139 prior to the period of extended
>operation , 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 steam dryer inspections will continue in accordance with the
>steam dryer monitoring plan, Revision 3
.>3.1.2.1.7  Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking, Cyclic Loading In the discussion column of LRA Table 3.1.1, Item 3.1.1-40, the applicant stated that cracking in stainless steel and nickel-alloy nozzles and penetrations in the reactor vessel is managed by the 3-170 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 managed using 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 documented in 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 Inservice Inspection Program and the Water Chemistry Control - BWR Program.
The staff reviewed the applicant's Inservice Inspection Program. This evaluation is documented in SER 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 inspec tions 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 aging effect/mechanism, as recommended by the GALL Report.
3.1.2.1.8  Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion Cracking In LRA Table 3.1.1, Item 3.1.1-41, the applicant stated that cracking in stainless steel and nickel-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.
In LRA Table 3.1.2-3, for pump casings and valve bodies of CASS, as well as piping, fittings, flow elements, and thermowells of stainless steel, the applicant augments the BWR Stress Corrosion
 
Cracking Program and the Water Chemistry Progr ams 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 the scope 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 components less than 4 inches nominal pipe size (NPS) are not within the scope of the BWR Stress Corrosion
 
Cracking Program. The FWthermal FW thermal sleeves of stainless steel and nickel-based alloy
>
3-171 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 the FW 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 are managed 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 in SER 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 of the 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 aging effect/mechanism, as recommended by the GALL Report.
3.1.2.1.9  Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking, Irradiation-Assisted Stress Corrosion Cracking In the discussion column of LRA Table 3.1.1, Item 3.1.1-44, the applicant stated that cracking due 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, not mechanically 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 Chemistry Control-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.
3-172 On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
3.1.2.1.10  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 of material in stainless steel and nickel-alloy components of the reactor vessel internals is managed
 
by 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 Inspection Program 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 applicant included 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 aging effect/mechanism, as recommended by the GALL Report.
3.1.2.1.11  Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking (For Stainless Steel Only), and Thermal and Mechanical Loading In the discussion column of LRA Table 3.1.1, Item 3.1.1-48, the applicant stated that cracking of Class 1 stainless steel components less than 4 in ches 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-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.
The staff asked the applicant to justify the omission of ISI from the management of aging for Class 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, and branch
 
connections less than 4 inches NPS consistent with the GALL Report and therefore acceptable.
3-173 The staff also asked the applicant for confirmation that CRD accumulators and condensing pots were 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 NPS and 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 the applicant'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 drives exposed to treated water greater than 270F in the RCPB is to be managed using "Inservice Inspection Program." The staff's review of the applicant's Inservice Inspection Program is documented in SER Section 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 aging effect/mechanism, as recommended by the GALL Report.
3.1.2.1.12  Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking, Irradiation-Assisted Stress Corrosion Cracking In the discussion column of LRA Table 3.1.1, Item 3.1.1-49, the applicant stated that VYNPS has welded 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 is not 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 Corrosion Cracking In the discussion column of LRA Table 3.1.1, Item 3.1.1-50, the applicant stated that the Reactor Head 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 Inspection Program. 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.
3-174 The staff noted that the applicant was managing cracking of other low alloy steel pressure boundary 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 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. 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 identified above, appropriately addressed the aging effe ct/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 of Preload Due to Thermal Effects, Gasket Creep, and Self-Loosening In the discussion column of LRA Table 3.1.1, Item 3.1.1-52, the applicant stated that cracking due 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.
The staff reviewed the applicant's Inservice Inspection Program. This evaluation is documented in SER 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 and stainless 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 identified above, appropriately addressed the aging effe ct/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 Inservice Inspection 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 Inspection Program. 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.
3-175 The applicant's management of loss of fracture toughness due to thermal aging embrittlement of CASS 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 aging effect/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 the One-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 CRD
 
housings made of CASS.
During the audit and review, the applicant clarified the location and method of attachment of this component, which is welded to the inner surface of the main steam piping upstream of the main
 
steam isolation valves (MSIVs).The 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 aging effect/mechanism, as recommended by the GALL Report.
Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating
 
experience and proposals for managing 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 Recommended In LRA Section 3.1.2.2, the applicant further evaluates aging management, as recommended by the 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 3-176
* 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 corrosion cracking
* cracking due to primary water stress corrosion cracking
* wall thinning due to flow-accelerated corrosion
* changes in dimensions due to void swelling
* cracking due to stress corrosion cracking and primary water stress corrosion cracking
* cracking due to stress corrosion cracking, primary water stress corrosion cracking, and irradiation-assisted stress corrosion cracking
* quality assurance for aging management of nonsafety-related components For component groups evaluated in the GALL Report, for which the applicant claimed 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 Appendix 3.1.2.2. The staff's review of the applicant'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 must evaluate 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 3.1.2.2.2 criteria:
3-177  (1)LRA Section 3.1.2.2.2 addresses loss of material in steel components of the reactor pressure 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 crevice corrosion 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.
LRA Section 3.1.2.2.2 states that loss of material due to general, pitting, and crevice corrosion in steel components of the reactor pressure vessel exposed to reactor coolant is
 
managed by the Water Chemistry Control-BW R Program. The effectiveness of the Water Chemistry Control-BWR Program will be conf irmed 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 therefore acceptable.    (2)LRA Section 3.1.2.2.2 addresses loss of material in other steel components within the RCPB 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 corrosion may 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, c ontrol 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 effectiv eness 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 isolation condenser components. VYNPS does not have an isolation condenser, however, loss of 3-178 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 Progr am through an inspection of a representative sample of components crediting this program including areas of stagnant flow. For some
 
components, the Inservice Inspection Pr ogram 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 therefore acceptable.  (3)LRA Section 3.1.2.2.2 addresses loss of material of stainless steel, nickel alloy, and steel with stainless steel or nickel alloy cladding flanges, nozzles, penetrations, pressure
 
housings, safe ends, and vessel shells, heads and welds exposed to reactor coolant due
 
to pitting and crevice corrosion.
SRP-LR Section 3.1.2.2.2 states that loss of material due to pitting and crevice corrosion may occur in stainless steel, nickel alloy, and steel with stainless steel or nickel alloy
 
cladding 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, c ontrol 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 effectiv eness 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 crevice corrosion in stainless steel, nickel-alloy and steel with stainless steel cladding components
 
of the reactor pressure vessel, and loss of material in stainless steel (including CASS)
 
components of the RCPB exposed to reactor c oolant 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 therefore acceptable.  (4)LRA Section 3.1.2.2.2 addresses that this paragraph in the SRP-LR applies to PWRs only.
SRP-LR Section 3.1.2.2.2 states that loss of material due to general, pitting, and crevice corrosion may occur in the steel PWR steam generator upper and lower shell and 3-179 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 does not apply to VYNPS.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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 required by 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 sta ff concludes that the applicant's programs meet SRP-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 Corrosion Cracking The 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 alloy BWR 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 the stainless steel and nickel alloy BWR top head enclosure vessel flange leak detection lines.
3-180 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 the One-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-Time Inspection 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.
The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the pr eventive 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 in stainless 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 exis ting 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-LR Section 3.1.2.2.4 does not apply to VYNPS.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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 not applicable 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 PWRs only.SRP-LR Section 3.1.2.2.5 stated that crack growth due to cyclic loading could occur in reactor vessel shell forgings clad with stainless steel using a high-heat-input welding process. Growth of 3-181 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-input welding process.
On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS.
3.1.2.2.6  Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void Swelling The 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 PWRs only.SRP-LR Section 3.1.2.2.6 states that loss of fracture toughness due to neutron irradiation embrittlement 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 PWR components.
On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS.
 
Based on the programs identified above, the sta ff 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 to PWRs only.
SRP-LR Section 3.1.2.2.7 states that cracking due to SCC may occur in the PWR stainless steel reactor vessel flange leak detection lines and bottom-mounted instrument 3-182 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. The
 
GALL 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 PWR components.
On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS.
 
Based on the programs identified above, the sta ff 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 lines due to cyclic loading.
SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in the stainless 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 pump sensing 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 RCS pressure 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 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).  (2)LRA Section 3.1.2.2.8 addresses the applicant stated that this paragraph in the SRP-LR pertains to BWR isolation condenser components. In LRA Section 3.1.2.2.8, the applicant
 
stated that VYNPS does not have an isolation condenser.
3-183 SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in steel and stainless 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 te mperature 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 in SRP-LR Section 3.1.2.2.8 does not apply to VYNPS.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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 PWRs only.SRP-LR Section 3.1.2.2.9 states that loss of preload due to stress relaxation may occur in stainless 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 staff finds 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 to PWRs only.
SRP-LR Section 3.1.2.2.10 states that loss of material due to erosion may occur in steel steam generator 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.
3-184 On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS.
3.1.2.2.11  Cracking Due to Flow-Induced Vibration
 
The 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-induced vibration.
SRP-LR Section 3.1.2.2.11 states that loss of material due to erosion may occur in steel steam generator 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 significantly
 
underestimated. 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 consecutive refueling
 
outages beginning with the spring 2007 refueling outage.
The staff reviewed plant experience at Hatch and Brunswick related to plant transients after extended 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 steam dryers 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 to flow-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.
3-185 The staff finds that since the applicant has committed (Commi t ment #37) to implement
>BWRVIP-139 as approved by the staff , if the staff does approve BWRVIP-139 prior to the period
>of extended operation , 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 acceptable method 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 the applicant'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 Corrosion Cracking The 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 to PWRs only.
SRP-LR Section 3.1.2.2.12 states that cracking due to SCC and IASCC may occur in PWR stainless 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 staff finds that this aging effect does not require management at VYNPS.
3.1.2.2.13  Cracking Due to Primary Water Stress Corrosion Cracking
 
The 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 to PWRs only.
3-186 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 such
 
as 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 staff finds 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 to PWRs only.
SRP-LR Section 3.1.2.2.14 states that wall thinning due to flow-accelerated corrosion may occur in steel FW inlet rings and supports. The GALL Report references IN 91-19, ?Steam Generator Feedwater 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 staff finds that this aging effect does not require management at VYNPS 3.1.2.2.15  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 to PWRs only.
SRP-LR Section 3.1.2.2.15 states that changes in dimensions due to void swelling may occur in stainless 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
 
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 staff finds that this aging effect does not require management at VYNPS.
3-187 3.1.2.2.16  Cracking Due to Stress Corrosion Cracking and Primary Water Stress Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.16 against the following SRP-LR Section 3.1.2.2.16 criteria: In LRA Section 3.1.2.2.16, the applicant stated that this paragraph in the SRP-LR applies to PWRs only.
SRP-LR Section 3.1.2.2.16 states that cracking due to SCC 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 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 staff finds 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 Cracking The 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 to PWRs only.
SRP-LR Section 3.1.2.2.17 states that cracking due to SCC, PWSCC, and IASCC may occur in PWR 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.
On the basis that VYNPS does not have any components subject to this aging effect, the staff finds 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 the staff found acceptable.
3-188 Conclusion. On the basis of its review, for applicable component groups evaluated in the GALL Report for which the applicant has claimed consistency with the GALL Report, and for which the
 
GALL Report recommends further evaluation, the staff 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 Report Summary of Technical Information in the Application. In LRA Tables 3.1.2-1 through 3.1.2-3, 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.
In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant indicated, via notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line
 
item in the GALL Report. The applicant provided fu rther 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, materi al, 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 in the 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 the reactor vessel component groups.
In LRA Table 3.1.2-1, the applicant proposed to manage loss of material from low-alloy steel closure flange studs, nuts, washers and bushings exposed to air using AMP B.1.23, "Reactor
 
Head Closure Studs Program."
The staff reviewed the Reactor Head Closure Studs Program and its evaluation is documented in SER 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.
3-189 In LRA Table 3.1.2-1, the applicant proposed to manage loss of material from low-alloy steel stabilizer 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 SER Section 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 on the CRD return line exposed to treated water greater than 270F using the BWR CRD Return Line 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 ReturnLine 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.
 
With respect to the aging degradation of the capped CRD return line nozzle, the applicant stated
 
that 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 3-190 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 the material 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 resistance
 
to 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 of the 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.
In LRA Table 3.1.2-1, the applicant proposed to manage cracking of the low-alloy steel bottom head, 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 Chemistry
>Control - BWR Program.
The staff reviewed the Inservice Inspection Program and the Water Chemistry Control - BWR Program. 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 Inspecti on Program and the Water Chemistry Control -
BWR Program.
3-191 In LRA Table 3.1.2-1, the applicant proposed to manage fatigue damage (cracking-fatigue) of the stainless 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 managing cracking 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 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).
3.1.2.3.2  Reactor Vessel Internals Summary of Aging Management Evaluation - LRA Table 3.1.2-2 The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for the reactor vessel internals component groups.
In LRA Table 3.1.2-2, the applicant proposed to manage loss of preload of stainless steel core plate rim hold-down bolts exposed to treated water greater than 270F using a TLAA.
The core plate rim hold-down bolts are subject to stress relaxation due to thermal and irradiation effects 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 rim hold-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.
 
3-192 On the basis of its review, the staff finds that, with Commitment #29, the applicant has appropriately evaluated the AMR results of ma terial, 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 - LRA Table 3.1.2-3 The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for the RCPB component groups.
In LRA Table 3.1.2-3, the applicant proposed to manage cracking of low-alloy and stainless steel bolting 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 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).
3.1.2.3.4  Aging Effect/Mechanism in Table 3.1.1 That are Not Applicable for VYNPS
 
The staff reviewed LRA Table 3.1.1, which prov ides a summary of aging management evaluations 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 lines inside 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 core shroud 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.
3-193 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 alloy piping, piping components, and piping elements exposed to closed cycle cooling water due to
 
pitting, 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 copper alloy 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 No Aging 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 effects were identified as a result of its aging review process.
In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant identified AMR line items where no aging effects 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 steel components 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 environment exhibits 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 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 3-194 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 Conclusion====
The staff concludes that the applicant has provided sufficient information 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).3.2  Aging Management of Engineered Safety Features Systems This 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 penetrations3.2.1  Summary of Technical Information in the Application LRA 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 operating 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.
 
====3.2.2 Staff====
Evaluation The staff reviewed LRA Section 3.2 to determine whether the applicant provided sufficient information 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 AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters described
 
in the GALL Report; however, the staff did verify that the material presented in the LRA was
 
applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's 3-195 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 which further 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, the staff 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, and AMPs listed in LRA Section 3.2 and addressed in the GALL Report.Table 3.2-1  Staff Evaluation for Engineered Safety Features Systems Components in the GALL ReportComponent Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP 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-specific AMP is to be
 
evaluated.
Reference NRC Information
 
Notice 94-63, "Boric Acid
 
Corrosion of
 
Charging Pump
 
Casings Caused by
 
Cladding Cracks" None Not applicable to BWRs Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-196 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
 
corrosion Water Chemistryand One-Time
 
Inspection 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 3.2.2.2.3)
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-specific AMP 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
 
corrosion Water Chemistryand One-Time
 
Inspection 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 3.2.2.2.3)
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
 
corrosion Lubricating 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)Partially 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-specific AMP 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-specific AMP is to be
 
evaluated.
Periodic Surveillance and
 
Preventive
 
Maintenance
 
Program (B.1.22)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 GALLReportAMP in LRAStaff Evaluation 3-197 Steel, stainless steel, and copper alloy heat
 
exchanger tubes
 
exposed to
 
lubricating oil
 
(3.2.1-9)Reduction of heat transfer due to
 
fouling Lubricating 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 heat exchanger tubes
 
exposed to treated water (3.2.1-10)
Reduction of heat transfer due to
 
fouling Water Chemistryand One-Time
 
Inspection 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 3.2.2.2.4)
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-specific AMP 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-specific AMP 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)Steel 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-specific AMP 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
 
corrosion Water Chemistryand One-Time
 
Inspection Water 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)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-198 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
 
corrosion Water Chemistryand One-Time
 
Inspection 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 3.2.2.2.8)
Steel piping, piping components, and
 
piping elements
 
exposed to
 
lubricating oil
 
(3.2.1-16)
Loss of material due to general, pitting, and crevice
 
corrosion Lubricating 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 to SCC and IGSCC BWR Stress Corrosion Cracking and Water Chemistry BWR Stress Corrosion 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)
Steel piping, piping components, and
 
piping elements
 
exposed to steam or treated water
 
(3.2.1-19)Wall thinning due toflow-accelerated
 
corrosionFlow-Accelerated CorrosionFlow-Accelerated Corrosion 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)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-199 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 the GALL 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 the GALL Report.
(See SER Section 3.2.2.1.11)
Steel closure bolting exposed 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 System Water Chemistry Control-Closed Cooling Water
 
Program (B.1.30.3)Consistent withGALL Report, which
 
recommends no
 
further evaluation (See SER Section 3.2.2.1)
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 heat exchanger components
 
exposed to closed cycle cooling water
 
(3.2.1-27)
Loss of material due to general, pitting, crevice, and
 
galvanic corrosionClosed-CycleCooling Water System Water Chemistry Control-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 GALLReportAMP in LRAStaff Evaluation 3-200 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 System Water Chemistry Control-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 due to 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 System Water Chemistry Control-Closed Cooling Water
 
Program (B.1.30.3)Consistent withGALL Report, which
 
recommends no
 
further evaluation (See SER Section 3.2.2.1)
External 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 corrosion External Surfaces MonitoringSystem 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)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-201 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
 
Components Periodic Surveillance and 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 System Containment 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 heat exchanger components
 
exposed to raw water (3.2.1-36)
Loss of material due to general, pitting, crevice, galvanic, and MIC, and
 
foulingOpen-Cycle CoolingWater System Service 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)
Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to raw water (3.2.1-37)
Loss of material due to pitting, crevice, and MICOpen-Cycle CoolingWater System Periodic Surveillance and 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 due to 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 heat exchanger components
 
exposed to raw water (3.2.1-39)
Loss of material due to pitting, crevice, and MIC, and
 
foulingOpen-Cycle CoolingWater System Service WaterIntegrity Program (B.1.26)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 GALLReportAMP in LRAStaff Evaluation 3-202 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 System Service WaterIntegrity Program (B.1.26)Consistent withGALL Report, which
 
recommends no
 
further evaluation (See SER Section 3.2.2.1)Copper alloy > 15percent Zn piping, piping components, piping elements, and heat exchanger
 
components
 
exposed to closed cycle cooling water
 
(3.2.1-41)
Loss of material due to selective leaching Selective Leaching of 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 due to selective leaching Selective Leaching of Materials Selective Leaching Program (B.1.25)Consistent withGALL Report, which
 
recommends no
 
further evaluation (See SER Section 3.2.2.1)Gray cast iron piping, piping
 
components, and
 
piping elements
 
exposed to soil
 
(3.2.1-43)
Loss of material due to selective leaching Selective Leaching of 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 motor cooler exposed to treated water
 
(3.2.1-44)
Loss of material due to selective leaching Selective Leaching of Materials Selective 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 GALLReportAMP in LRAStaff Evaluation 3-203 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 Acid CorrosionNoneNot applicable to BWRs 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 to BWRs 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 to BWRs 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 to BWRs 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 to BWRs Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-204 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 steel ducting exposed to
 
air - indoor
 
controlled (external)
 
(3.2.1-51)NoneNoneNoneNot applicable Glass piping elements exposed
 
to air - indoor
 
uncontrolled (external),
lubricating oil, raw water, treated water, or treated borated water (3.2.1-52)NoneNoneNoneConsistent with GALL 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)
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).
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-205 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 to BWRs The staff's review of the ESF systems component groups followed any one of several approaches. 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 Report Summary 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
* Service Water Integrity Program
* System Walkdown Program
* Water Chemistry Control - Auxiliary Systems Program
* Water Chemistry Control - BWR Program
* Water Chemistry Control - Closed Cooling Water Program 3-206 Staff Evaluation. LRA Tables 3.2.2-1 through 3.2.2-7 summarize AMRs for the ESF 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 claimed 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 the information 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 consistent with 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 consistent with 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.
3-207 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 the system, 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 Water Chemistry 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 Inspection Program 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 aging effect/mechanism, as recommended by the GALL Report.
The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience
 
and proposals for managing 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).
3.2.2.1.2  Loss of Material Due to Pitting and Crevice Corrosion
 
In the discussion column of LRA Table 3.2.1, Item 3.2.1-5, the applicant stated that the Water Chemistry 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 Inspection Program was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. The staff reviewed the 3-208 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 aging effect/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 Oil Analysis 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 Inspection Program 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 that is
 
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 exc hanger 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 application identified 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 Oil Analysis Program manages reduction of heat transfer in steel, stainless steel and copper alloy
 
components.
During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program 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 3-209 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 application identified 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 Water Chemistry 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 Inspection Program 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 aging effect/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 Water Chemistry 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 Inspection Program 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 3.2.1-14 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 aging effect/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 Water Chemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify 3-210 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 ESF system. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program 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 aging effect/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 Oil Analysis Program manages loss of material in steel components.
During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program 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, piping
 
components, 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.
3.2.2.1.9  Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion Cracking In the discussion column of LRA Table 3.2.1, Item 3.2.1-18, the applicant stated that the Water Chemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage cr acking due to SCC and IGSCC in stainless steel piping, piping components, and piping elements of the ESF system. The VYNPS Water Chemistry 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.
3-211 During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program 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 with the>Water Chemistry Control-BWR Program, One-Time Inspection Program, and Inservice Inspection
>Program appropriately addressed the aging e ffect/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 the Flow-Accelerated Corrosion Program will be used to manage wall thinning in steel piping, piping
 
components, 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 is documented 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 aging effect/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 System Walkdown 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 closure
 
bolting components.
During the audit and review, the staff asked the applicant to clarify the basis for using its System Walkdown 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 application identified 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 3-212 In the discussion column of LRA Table 3.2.1, Item 3.2.1-31, the applicant stated that the System Walkdown Program will be used to manage loss of material to external 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) in the ESF system.
The staff reviewed the applicant's System Walk down Program. This evaluation is documented in SER 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 aging effect/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 System Walkdown 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 Walk down Program. This evaluation is documented in SER 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 aging effect/mechanism, as recommended by the GALL Report.
3.2.2.1.14  Loss of Material Due to General, Pitting and Crevice Corrosion
 
In the discussion column of LRA Table 3.2.1, Item 3.2.1-34, the applicant stated that the Periodic Surveillance 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 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, 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.
3-213 On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
3.2.2.1.15  Loss of Material Due to General, Pitting, Crevice Corrosion, Microbiologically-Influenced Corrosion and Fouling In the discussion column of LRA Table 3.2.1, Item 3.2.1-35, the applicant stated that the Containment 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 is documented in SER Section 3.0.3.2.8, which the staff found acceptable. During the audit and
 
review, the staff confirmed that the Containm ent 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 aging effect/mechanism, as recommended by the GALL Report.
 
3.2.2.1.16  Loss of Material Due to General, Pitting, Crevice, Galvanic, Microbiologically-Influenced Corrosion and Fouling In the discussion column of LRA Table 3.2.1, Item 3.2.1-36, the applicant stated that the Service Water 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 and Preventive 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 aging effect/mechanism, as recommended by the GALL Report.
3.2.2.1.17  Loss of Material Due to Pitting, Crevice Corrosion and Microbiologically-Influenced Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-37, the applicant stated that the Periodic Surveillance 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 piping
 
elements exposed to raw water in the ESF system.
3-214 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 aging effect/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 of preload was not an AERM.
During the audit and review, the staff asked the applicant to justify the position that was taken in not 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 sta ff'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
 
all bolting. With this change, the applicant's management of loss of preload due to thermal effects, 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 and Commitment #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. The staff 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 Recommended Summary of Technical Information in the Application. In LRA Section 3.2.2.2, the applicant further evaluates 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 3-215
* 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 components Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant claimed 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.
 
3.2.2.2.1  Cumulative Fatigue Damage LRA Section 3.2.2.2.1 states that fatigue 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 4.3 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, this aging 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 PWR steel pump casings with stainless steel cladding exposed to treated borated water. The GALL
 
Report 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 this aging 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:
3-216  (1)LRA Section 3.2.2.2.3 addresses loss of material of internal surfaces of stainless steel piping 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 corrosion may occur on internal surfaces of stainless steel containment isolation piping, piping
 
components, 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.
The LRA states that loss of material due to pitting and crevice corrosion for internal surfaces of stainless steel piping and components in ESF systems exposed to treated
 
water is managed by the Water Chemistry C ontrol-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 Chemistry Control-BWR Program provides both the pr eventive 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 crevice corrosion may occur in stainless steel piping, piping components, and piping
 
elements 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 soil environment, 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 finds that 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 and aluminum piping and piping components exposed to treated water due to pitting and
 
crevice corrosion.
3-217 SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosion may occur in BWR stainless steel and aluminum piping, piping components, and piping
 
elements exposed to treated water. The existing AMP monitors and controls water
 
chemistry for BWRs to mitigate degradation. Ho wever, 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 effectiv eness 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 from pitting and crevice corrosion for BWR stainless steel 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 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. 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 piping and 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 corrosion may occur in stainless steel and copper alloy piping, piping components, and piping
 
elements 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 for copper 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 envir onment that is not conducive to corrosion.
Operating experience at VYNPS has confirm ed the effectiveness of this program in 3-218 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 (primarily water 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 Progr am, 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.  (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 corrosion may 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 the loss 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 finds that 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 piping components 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 corrosion may occur in stainless steel piping, piping components, piping elements, and tanks
 
exposed 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 stainless steel piping and piping components internally exposed to condensation is managed by the Periodic Surveillance and Preventive Maintenanc e 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 a plant-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, piping 3-219 components, piping elements, and tanks exposed to internal condensation. It is therefore acceptable to the staff.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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).
3.2.2.2.4  Reduction of Heat Transfer Due to Fouling
 
The 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 heat exchanger 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 occur in 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 heat exchanger 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 fouli ng. 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 (primarily water 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 heat exchanger tubes exposed to treated water in ESF systems due to fouling.
3-220 SRP-LR Section 3.2.2.2.4 states that reduction of heat transfer due to fouling may occur in 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.
The LRA states that reduction of heat transfer due to fouling for stainless steel heat exchanger tubes exposed to treated water in ESF systems is managed by the Water Chemistry Control-BWR Program. The effectiv eness 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 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. 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 sta ff concludes that the applicant's programs meet SRP-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 elastomer degradation, 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 elastomer degradation 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 the hardening 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 this aging effect is not applicable to VYNPS.
3.2.2.2.6  Loss of Material Due to Erosion 3-221 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 not applicable 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.
SRP-LR Section 3.2.2.2.6 states that loss of material due to erosion may occur in the stainless steel 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 loss of material due to erosion is not applicable.
On the basis that VYNPS does not have any components from this group, the staff finds that this aging 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, this aging 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 orific es 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 may occur 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 loss of 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 this aging effect is not applicable to VYNPS.
3.2.2.2.8  Loss of Material Due to General, Pitting, and Crevice Corrosion 3-222 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 and components in ESF systems 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 in BWR steel piping, piping components, and piping elements
 
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 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 effectiv eness 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 BWR steel 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 control of 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 primary containment 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, piping
 
components, 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 progr ams 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.
3-223 The LRA states that the loss of material due to general, pitting and crevice corrosion for internal surfaces of primary containment penetration steel piping and components
 
exposed to treated water is managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Cont rol-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 use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the pr eventive 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 ESF systems 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 crevice corrosion may occur in steel piping, piping components, and piping elements 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 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 steel piping 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 ex perience 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 (primarily water 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 sta ff concludes that the applicant's programs meet SRP-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 3-224 function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2.2.2.9  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion The 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, and
 
MIC.SRP-LR Section 3.2.2.2.9 states that loss of material due to general, pitting, crevice, 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 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 or without 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 period before 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-LR Section 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).
3-225 3.2.2.2.10  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 the staff found acceptable.
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for which the applicant has claimed consistency with the GALL Report, and for which the GALL
 
Report recommends further evaluation, the staff 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 Report Summary of Technical Information in the Application. In LRA Tables 3.2.2-1 through 3.2.2-7, the staff reviewed additional details of the 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 the combination 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 not evaluated 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 - LRA Table 3.2.2-1 The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for the RHRS component groups.
In LRA Table 3.2.2-1, the applicant proposed to manage cracking of stainless steel heat exchanger tubes exposed to a raw water environment using the Service Water Integrity Program.
3-226 The staff reviewed the applicant's Service Water Integrity Program and its evaluation is documented 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 materials for component types of bolting exposed to air-i ndoor (external) environment using the System Walkdown Program.
During the audit and review, the staff asked the applicant to clarify the basis for using its System Walkdown 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 ev aluation 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 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).
3.2.2.3.2  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 the CSS component groups.
In LRA Table 3.2.2-2, the applicant proposed to manage loss or material of carbon steel materials for component types of bolting exposed to air-i ndoor (external) environment using the System Walkdown Program.
During the audit and review, the staff asked the applicant to clarify the basis for using the System Walkdown 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 3-227 Program 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 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).
3.2.2.3.3  Automatic Depressurization System Summary of Aging Management Evaluation - LRA Table 3.2.2-3 The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for the automatic depressurization system component groups.
In LRA Table 3.2.2-3, the applicant proposed to manage loss or material of carbon steel materials for component types of bolting exposed to air-i ndoor (external) environment using the System Walkdown Program.
During the audit and review, the staff asked the applicant to clarify the basis for using the System Walkdown 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 ev aluation 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 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).
3.2.2.3.4  High Pressure Coolant Injection Sy stem Summary of Aging Management Evaluation -
LRA Table 3.2.2-4 The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the HPCIS component groups.
In LRA Table 3.2.2-4, the applicant proposed to manage loss of material wear of copper alloy heat exchanger tubes exposed to lube oil and treated water environments using the Heat
 
Exchanger Monitoring Program.
3-228 The staff reviewed the applicant's Heat Exc hanger Monitoring Program and its evaluation is documented 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 usi ng 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 environm ents using the Oil Analysis Program.
The staff reviewed the Oil Analysis Program and its evaluation is documented in SER Section 3.0.3.2.13. LRA Section A.2.1.22, states that the Oil Analysis Program maintains oil
 
systems free of contaminants (primarily wa ter 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 t hat 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 and stainless steel materials for component types of bolting exposed to an air-indoor (external) and
 
air-outdoor (external) environment us ing the System Walkdown Program.
During the audit and review, the staff asked the applicant to clarify the basis for using the System Walkdown 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 Bolt ing 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.
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).
3-229 3.2.2.3.5  Reactor Core Isolation Cooling Sy stem Summary of Aging Management Evaluation -
LRA Table 3.2.2-5 The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for the reactor 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 and aluminum heat exchanger tubes and steam heat ers exposed to treated water and a lube oil environment using the Heat Exchanger Monitoring Program.
The staff review the Heat Exchanger Monitori ng Program and its evaluation is documented in SER Section 3.0.3.3.1. The Heat Exchanger Moni toring 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 and stainless steel materials for component types of bolting exposed to an air-indoor (external) and
 
air-outdoor (external) environment us ing the System Walkdown Program.
During the audit and review, the staff asked the applicant to clarify the basis for using the System Walkdown 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 Bolt ing 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 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 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 3-230 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 Su mmary of Aging Management Evaluation - LRA Table 3.2.2-6 The staff reviewed LRA Table 3.2.2-6, which summarizes the results of AMR evaluations for the SGTS component groups.
In LRA Table 3.2.2-6, the applicant proposed to manage loss of material of carbon steel materials for component types of bolting exposed to an ai r-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 System Walkdown 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 ev aluation 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 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).
3.2.2.3.7  Primary Containment Penetrations Summary of Aging Management Evaluation - LRA Table 3.2.2-7 The staff reviewed LRA Table 3.2.2-7, which summarizes the results of AMR evaluations for the primary containment penetrations component groups.
In LRA Table 3.2.2-7, the applicant proposed to manage loss of material of carbon steel materials for component types of piping and valve body ex posed 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 in SER 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 associated
 
bases and (b) periodic surveillance of reactor containment penetrations and isolation valves is 3-231 performed so that proper maintenance and repairs are made during the service life of containment, and systems and components penetrati ng 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 materials for component types of bolting exposed to an ai r-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 System Walkdown 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 ev aluation 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 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).
3.2.2.3.8  Aging Effects/Mechanisms Not Applicable at VYNPS - LRA Table 3.2.1
 
The staff reviewed LRA Table 3.2.1, which prov ides a summary of aging management evaluations 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 CASS piping, 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.
The 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 ESF
 
systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this
 
component type.
3-232 In LRA Table 3.2.1, Item 3.2.1-21, the applicant stated 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.The staff reviewed, in the LRA and supporting documents, the ESF systems for any high-strength steel closure bolting exposed to air with steam or water leakage due to cyclic loading. The staff
 
determines 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 closure bolting 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 of steel 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, piping components, 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 par t of other safety systems that are evaluated separately.
The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of material of steel piping, piping components, and piping elements exposed to closed cycle cooling water due
 
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 to general, 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 staff finds that
 
this aging effect is not applicable to VYNPS for this component type.
In LRA Table 3.2.1, Item 3.2.1-29, the applicant stated that the loss of material of copper alloy piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water due to pitting, crevice, and galvanic corrosion is not applicable at VYNPS.
 
There are no copper alloy components exposed to clos ed cycle cooling water in the ESF system.
The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of material of 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 heat
 
exchanger components exposed to closed cycle c ooling 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 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.
3-233 In LRA Table 3.2.1, Item 3.2.1-33, the applicant stated 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 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 material of 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 st aff 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 steel containment 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 material of stainless steel containment isolation piping and components internal surfaces exposed to raw
 
water 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 raw
 
water 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 surfaces
 
exposed 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 copper alloy 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 material of copper alloy greater than15 percent Zinc piping, piping components, piping elements, and heat
 
exchanger components exposed to closed cycle cooli ng 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 water due to selective leaching is not applicable to VYNPS. On the basis that there are no copper
 
alloy greater than 15 percent zinc piping, piping components, piping elements, and heat
 
exchanger components exposed to closed cycle cooli ng 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 iron piping, piping components, and piping elements exposed to soil due to selective leaching is not
 
applicable at VYNPS. There are no gray cast iron piping, piping components, and piping elements
 
exposed to soil in the ESF system.
3-234 The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of material of gray cast iron piping, piping components, and pi ping elements exposed to soil due to selective leaching. The staff finds that the loss of material of gray cast iron piping, piping components, and
 
piping elements exposed to soil due to selective leaching is not applicable to VYNPS. On the
 
basis that there are no gray cast iron pipi ng, piping components, and piping elements exposed to soil 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 (LRA Tables 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 aging effects 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's analysis 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 dry atmospheres 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 an
 
indoor (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.
On the basis of its review, the staff finds that the applicant appropriately evaluated the 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).
 
====3.2.3 Conclusion====
The staff concludes that the applicant has provided sufficient information 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).3.3  Aging Management of Auxiliary Systems 3-235 This section of the SER documents the staff's review of the applicant's AMR results for the auxiliary systems component s 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 Application LRA Section 3.3 provides AMR results fo r the auxiliary system s components and component groups. LRA Table 3.3.1, "Summary of Aging M anagement 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 fo r the auxiliary system s components and component groups.The applicant's AMRs evaluated and incorporated applicable plant-specific and industry operating experience 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.
 
====3.3.2 Staff====
Evaluation The staff reviewed LRA Section 3.3 to determine whether the applicant provided sufficient information to demonstrate that the effects of aging for the auxiliary systems components that are within the scope of license renewal and subject to an AMR will be adequately managed so that
 
the intended 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 AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters described
 
in the GALL Report; however, the staff did verify that the material presented in the LRA was
 
applicable and that the applicant 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 and for which further evaluation is recommended. The staff confirmed that the applicant's further 3-236 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 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 3.3.2.3.
Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or monitoring aging for the auxiliary 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 3.3-1 summarizes the staff's evaluation of components, aging effects/mechanisms, and AMPs, listed in LRA Section 3.3 and addressed in the GALL Report.Table 3.3-1  Staff Evaluation for Auxiliary System Components in the GALL ReportComponent Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation Steel cranes -
structural girders
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.3.1-1)Cumulative fatigue damageTLAA to be evaluated 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)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-237 Stainless steel heat exchanger
 
tubes exposed to treated water
 
(3.3.1-3)Reduction of heat transfer due to
 
fouling Water Chemistryand One-Time
 
Inspection Water 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 SCC Water Chemistryand One-Time
 
Inspection Water ChemistryControl-BWR
 
Program (B.1.30.2);
One-Time Inspection
 
Program (B.1.21)
Not applicable.(See SER Section 3.3.2.2.3)
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 Surveillance and 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 steel non-regenerative
 
heat exchanger
 
components
 
exposed to treated borated water
> 60C (> 140F)(3.3.1-7)Cracking due toSCC and cyclic
 
loading Water 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 to BWRs (See SER Section 3.3.2.2.4)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-238 Stainless steel regenerative heat
 
exchanger components
 
exposed to treated borated water
> 60C (> 140F)(3.3.1-8)Cracking due toSCC and cyclic
 
loading Water 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 to BWRs (See SER Section 3.3.2.2.4)
Stainless steel high-pressure
 
pump casing in PWR chemical
 
and volume control system
 
(3.3.1-9)Cracking due toSCC and cyclic
 
loading Water 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 to BWRs (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 Surveillance and 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 lining exposed to treated water or treated borated water
 
(3.3.1-12)
Hardening and loss of strength due to
 
elastomer degradation A plant-specific AMP 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)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-239 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)
Steel piping, piping component, and piping
 
elements exposed
 
to lubricating oil
 
(3.3.1-14)
Loss of material due to general, pitting, and crevice
 
corrosion Lubricating 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
 
corrosion Lubricating 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
 
corrosion Lubricating 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
 
corrosion Water Chemistryand One-Time
 
Inspection Water 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 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 Sections 3.3.2.1.8 and
 
3.3.2.2.7)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-240Steel (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)
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 heat exchanger components
 
exposed to
 
lubricating oil
 
(3.3.1-21)
Loss of material due to general, pitting, crevice, and MIC, and fouling Lubricating 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 due to 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 due to pitting and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water 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)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-241 Stainless steel and aluminum
 
piping, piping
 
components, and
 
piping elements
 
exposed to treated water (3.3.1-24)
Loss of material due to pitting and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water 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)
Copper alloy HVAC piping, piping components, piping elements
 
exposed to
 
condensation (external)
 
(3.3.1-25)
Loss of material due to pitting and crevice
 
corrosion A plant-specific AMP 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 due to pitting and crevice
 
corrosion Lubricating 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 steel HVAC ducting and
 
aluminum HVAC
 
piping, piping
 
components and
 
piping elements
 
exposed to
 
condensation
 
(3.3.1-27)
Loss of material due to pitting and crevice
 
corrosion A plant-specific AMP 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 due to pitting and crevice
 
corrosion A plant-specific AMP is to be
 
evaluated.
Periodic Surveillance and 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)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-242 Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to soil
 
(3.3.1-29)
Loss of material due to pitting and crevice
 
corrosion A plant-specific AMP 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)
Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to sodium
 
pentaborate
 
solution (3.3.1-30)
Loss of material due to pitting and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water 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 due to pitting, crevice, and galvanic
 
corrosion Water Chemistryand One-Time
 
Inspection Water 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 due to 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 due to pitting, crevice, and MIC Lubricating 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 due to WearPlant-specificNoneNot applicable.(See SER Section 3.3.2.2.13)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-243Steel with stainless steel
 
cladding pump
 
casing exposed to
 
treated borated water (3.3.1-35)
Loss of material due to cladding breach A plant-specific AMP is to be
 
evaluated.
 
Reference NRC
 
IN 94-63, "Boric Acid
 
Corrosion of
 
Charging Pump
 
Casings Caused by
 
Cladding Cracks."NoneNot applicable to BWRs Boraflex 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, IGSCC BWR Reactor WaterCleanup System Water ChemistryControl-BWR Program (B.1.30.2); One-Time
 
Inspection Program (B.1.21)Consistent with the GALL 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 SCC BWR Stress Corrosion Cracking and Water Chemistry Water ChemistryControl-BWR Program (B.1.30.2); One-Time
 
Inspection Program (B.1.21)Consistent with the GALL 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
 
corrosion Aboveground SteelTanksSystem Walkdown Program (B.1.28)Consistent with the GALL Report.
(See SER Section 3.3.2.1.24)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-244 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.)Steel closure bolting 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 the GALL 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 the GALL Report.
(See SER Section 3.3.2.1.25)
Steel closure bolting 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 the GALL 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 System Water Chemistry Control-Closed Cooling Water
 
Program (B.1.30.3);
One-Time Inspection
 
Program (B.1.21)Consistent with the GALL Report.
(See SER Section 3.3.2.1.26)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-245 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 System Water Chemistry Control-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 the GALL 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 System Water Chemistry Control-Closed Cooling Water
 
Program (B.1.30.3);
One-Time Inspection
 
Program (B.1.21)Consistent with the GALL 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 due to MICClosed-CycleCooling Water System Water Chemistry Control-Closed Cooling Water
 
Program (B.1.30.3);
One-Time Inspection
 
Program (B.1.21)Consistent with the GALL 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 due to pitting and crevice
 
corrosionClosed-CycleCooling Water System Water Chemistry Control-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 the GALL Report.
(See SER Section 3.3.2.1.30)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-246 Copper alloy piping, piping
 
components, piping elements, and heat exchanger components
 
exposed to closed cycle cooling water (3.3.1-51)
Loss of material due to pitting, crevice, and galvanic
 
corrosionClosed-CycleCooling Water System Water Chemistry Control-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 the GALL 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 System Water Chemistry Control-Closed Cooling Water
 
Program (B.1.30.3);
One-Time Inspection
 
Program (B.1.21)Consistent with the GALL 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
 
corrosion Compressed Air Monitoring Instrument Air Quality Program (B.1.16)Consistent with the GALL 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 due to pitting and crevice
 
corrosion Compressed Air Monitoring Instrument Air Quality Program (B.1.16)Consistent with the GALL 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 corrosion External Surfaces MonitoringSystem Walkdown Program (B.1.28)Consistent with the GALL Report.
(See SER Section 3.3.2.1)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-247 Steel HVAC ducting and
 
components
 
external surfaces
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.3.1-56)
Loss of material due to general corrosion External Surfaces MonitoringSystem Walkdown Program (B.1.28)Consistent with the GALL 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 corrosion External Surfaces MonitoringSystem Walkdown Program (B.1.28)Consistent with the GALL Report.
(See SER Section 3.3.2.1)
Steel external surfaces exposed
 
to air-indoor
 
uncontrolled (external),
air-outdoor (external), and
 
condensation (external)
 
(3.3.1-58)
Loss of material due to general corrosion External Surfaces MonitoringSystem Walkdown Program (B.1.28)Consistent with the GALL Report.
(See SER Section 3.3.2.1)
Steel heat exchanger components
 
exposed to
 
air-indoor
 
uncontrolled (external) or
 
air-outdoor (external)
(3.3.1-59)
Loss of material due to general, pitting, and crevice
 
corrosion External Surfaces MonitoringSystem Walkdown Program (B.1.28)Consistent with the GALL 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
 
corrosion External Surfaces MonitoringSystem Walkdown Program (B.1.28)Consistent with the GALL Report.
(See SER Section 3.3.2.1)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-248 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 the GALL 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 due to pitting and crevice
 
corrosionFire ProtectionNoneNot applicable.(There are no
 
aluminum components with intended
 
functions exposed to raw water in the auxiliary systems.)
Steel fire rated doors exposed to
 
air-outdoor or
 
air-indoor
 
uncontrolled
 
(3.3.1-63)
Loss of material due to WearFire ProtectionFire Protection Program (B.1.12.1)Consistent with the GALL 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
 
corrosionFire 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 aggregatesFire Protection and Structures
 
Monitoring ProgramNoneThis line item was not 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 aggregatesFire Protection and Structures
 
Monitoring ProgramNoneThis line item was not used. Reinforced
 
concrete structural
 
fire barriers are
 
evaluated as
 
structural
 
components in SER
 
Section 3.5.
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-249 Reinforced 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 steelFire Protection and Structures
 
Monitoring ProgramNoneThis line item was not 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 the GALL 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 due to pitting and crevice
 
corrosion, and
 
foulingFire Water SystemFire Water System Program (B.1.12.2);
Fire Protection
 
Program (B.1.12.1)Consistent with the GALL 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 due to 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 the GALL 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
 
Components Periodic Surveillance and Preventive
 
Maintenance Program (B.1.22)Consistent with the GALL 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
 
Components Periodic Surveillance and Preventive
 
Maintenance Program (B.1.22)Consistent with the GALL Report.
(See SER Section 3.3.2.1.41)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-250 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 of Overhead Heavy
 
Load and Light Load (Related to
 
Refueling) Handling Systems Periodic Surveillance and Preventive
 
Maintenance Program (B.1.22); Structures
 
Monitoring Program (B.1.27.2)Consistent with the GALL Report.
(See SER Section 3.3.2.1.42)
Steel cranes - rails exposed to
 
air-indoor
 
uncontrolled (external)
 
(3.3.1-74)
Loss of material due to Wear Inspection of Overhead 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 System Service Water Integrity Program (B.1.26)Consistent with the GALL Report.
(See SER Section 3.3.2.1)
Steel heat exchanger components
 
exposed to raw water (3.3.1-77)
Loss of material due to general, pitting, crevice, galvanic, and MIC, and foulingOpen-Cycle CoolingWater System Service Water Integrity Program (B.1.26);
 
Heat Exchanger
 
Monitoring Program (B.1.14)Consistent with the GALL Report.
(See SER Section 3.3.2.1.43)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-251 Stainless steel,nickel alloy, and
 
copper alloy
 
piping, piping
 
components, and
 
piping elements
 
exposed to raw water (3.3.1-78)
Loss of material due to 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 due to pitting and crevice
 
corrosion, and
 
foulingOpen-Cycle CoolingWater System Service Water Integrity Program (B.1.26)Consistent with the GALL 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 due to 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 due to pitting, crevice, and MIC, and foulingOpen-Cycle CoolingWater System Service Water Integrity Program (B.1.26)Consistent with the GALL Report.
(See SER Section 3.3.2.1)Copper alloy heat exchanger components
 
exposed to raw water (3.3.1-82)
Loss of material due to pitting, crevice, galvanic, and MIC, and foulingOpen-Cycle CoolingWater System Service Water Integrity Program (B.1.26)Consistent with the GALL Report.
(See SER Section 3.3.2.1)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-252 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 System Service Water IntegrityProgram (B.1.26); Fire
 
Protection Program (B.1.12.1)Consistent with the GALL Report.
(See SER Section 3.3.2.1.44)Copper alloy > 15percent 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 due to selective leaching Selective Leaching of Materials Selective Leaching Program (B.1.25)Consistent with the GALL 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 due to selective leaching Selective Leaching of Materials Selective Leaching Program (B.1.25)Consistent with the GALL 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 Structures Monitoring 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 to BWRs Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-253 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 to BWRs Steel bolting and external surfaces exposed to air with borated water
 
leakage (3.3.1-89)
Loss of material due to Boric acid
 
corrosionBoric Acid CorrosionNoneNot applicable to BWRs 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 to BWRs 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 due to pitting and crevice
 
corrosionWater ChemistryNoneNot applicable to BWRs Galvanized 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.)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-254 Glass piping elements 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 the GALL 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 with GALL 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 the GALL 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 the GALL Report.
(See LRA Section 3.3.2.1)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-255 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 to BWRs The staff's review of the auxiliary systems component groups followed any one of several approaches. 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 component s is documented in SER Section 3.0.3.3.3.2.1  AMR Results Consistent with the GALL Report Summary of Technical Information in the Amended Application. LRA Section 3.3.2.1 identifies the 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
* Selective Leaching Program 3-256
* Service Water Integrity Program
* System Walkdown Program
* Water Chemistry Control - Auxiliary Systems Program
* Water Chemistry Control - BWR Program
* Water Chemistry Control - Closed Cooling Water Program Staff Evaluation. LRA Tables 3.3.2-1 through 3.3.2-12 and Tables 3.3.2-13-1 through 3.3.2-13-58 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 claimed 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 the information 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 consistent with 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.
3-257 Note D indicates that the component for the AMR line item, although different from, is consistent with 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'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-BWR Program, augmented by the One-Time Inspection Pr ogram 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 Inspection Program was not explicitly identifi ed 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.
3-258 On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
3.3.2.1.2  Cracking Due to Stress Corrosion Cracking
 
For cracking due to SCC of stainless steel and stainless clad steel heat exchanger components exposed to treated water greater than 60C (greater than140F), the GALL Report recommends a plant-specific program.
In LRA Table 3.3.1, Item 3.3.1-5, the applicant stated that cracking in stainless steel heat exchanger tubes exposed to treated water greater than140F is managed by the Water Chemistry Control-BWR Program. The One-Time In spection 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 Inspection Program was not explicitly identified in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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 Inspecti on 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 provi des 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 aging effect/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, and piping 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 exhaust components will be managed by the Periodic Surv eillance 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.
On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
3.3.2.1.4  Hardening and Loss of Strength Due to Elastomer Degradation 3-259 For hardening and loss of strength due to elastomer degradation of elastomer seals and components 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 of elastomer components exposed to indoor air w ill 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 aging effect/mechanism, as recommended by the GALL Report.
3.3.2.1.5  Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General Corrosion For reduction of neutron-absorbing capacity and loss of material due to general corrosion of boral, 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 Chemistry Control-BWR Program manages the degradation of boral.
During the audit and review, the staff asked the applicant how a purely preventive program could address 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 LRA is 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-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 elem ents 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 the application identified above, appropriately addressed the aging effect/mechanism, as
 
recommended by the GALL Report.
3-260 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, 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."
In the discussion column of LRA Table 3.3.1, Item 3.3.1-14, the applicant stated that the Oil Analysis Program, manages loss of material in steel components.
During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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 exposed to
 
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 the application 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, 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 3.3.1-17, the applicant stated that the loss of material in steel components is managed by the Water Chemis try 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 Inspection Program was not explicitly identified in the system tables (Tables 3.3.
2.-1 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 3-261 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 aging effect/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 steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel
 
exhaust, 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 and Preventive Maintenance Program and the Fire Pr otection 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 documented in 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 car bon steel expansion joints in the EDG system, stainless steel expansion joints and carbon steel piping, silencers, and turbochargers in the
 
EDG, 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 the aging effect/mechanism, as recommended by the GALL Report.
3.3.2.1.9  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion, and Fouling For loss of material due to general, pitting, crevice, and MIC, and fouling of steel piping, piping components, 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 Program manages loss of material in steel components.
During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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 3-262 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 progr am 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 oil consistent with the GALL Report and therefore 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.
3.3.2.1.10  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion, and Fouling For loss of material due to general, pitting, crevice, and MIC, and fouling of steel heat exchanger components exposed to lubricating oil, the GA LL Report recommends programs consistent withGALL 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 manages loss of material in steel heat exchanger components.
During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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 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 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 aging effect/mechanism, as recommended by the GALL Report.
3.3.2.1.11  Loss of Material Due to Pitting and Crevice Corrosion 3-263 For loss of material due to pitting and crevice corrosion of stainless steel and steel with stainless steel cladding heat exchanger components exposed to treated water, the GALL Report
 
recommends programs consistent with GALL AMP XI.M2, "Water Chemistry" and GALLAMP 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 steel heat exchanger components is managed by the Wa ter Chemistry Control-BWR Program. The One-Time Inspection Program will be used to veri fy the effectiveness of the Water Chemistry Program.During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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 O ne-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 aging effect/mechanism, as recommended by the GALL Report.
3.3.2.1.12  Loss of Material Due to Pitting and Crevice Corrosion
 
For 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 GALLAMP 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 steel components is managed by the Water Chemis try 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 Inspection Program was not explicitly identified in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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 Inspecti on 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 provi des both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicant's 3-264 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 aging effect/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, piping components, 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 Maintenanc e Program, Service Water Integrity Program and the Heat Exchanger Monitoring Program w ill manage loss of material in copper alloy components.
The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion from copper-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 SER Section 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.
The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion from copper-alloy (less than15 percent zinc) heat exchanger tubes exposed to condensation in the
 
HVAC system is to be managed using the Pe riodic Surveillance and Preventive Maintenance Program, a plant-specific AMP.
The staff's review of the applicant's Periodic Surveillance and Preventive Maintenance Program 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 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 from copper-alloy (greater than15 percent zinc) heat exchanger tubes exposed to condensation in the
 
SW and HVAC systems is to be managed usi ng the Service Water Integrity Program.
The staff's review of the applicant's Service Water Integrity Program is documented in SER Section 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 from copper-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.
3-265 The staff's review of the applicant's System Walkdown Program is documented in SER Section 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 from copper-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 SER Section 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 the aging 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, 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."
In LRA Table 3.3.1, Item 3.3.1-26, the applicant stated that the Oil Analysis Program manages loss of material in copper alloy components.
During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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 to
 
lubricating 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 the application 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 3-266 For loss of material due to pitting and crevice corrosion of stainless steel HVAC ducting and aluminum HVAC piping, piping components and piping elements exposed to condensation, the GALL 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 Maintenanc e 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 Syst em Walkdown Program, Periodic Surveillance and Preventive Maintenance Program, and the Servic e 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 also
 
reviewed 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 steel piping, tanks, and valve bodies of the EDG system exposed to untreated air is to be managed
 
using the Periodic Surveillance and Preventiv e Maintenance Program, a plant-specific AMP.
The staff's evaluation of the applicant's Periodic Surveillance and Preventive Maintenance Program 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 stainless steel 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 SER Section 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 in condensation from stainless steel piping, tubing, and valve bodies of the RHRSW system as well
 
as from bolting, expansion joints, indicators, orifices, piping, tubing, thermowells, and valve
 
bodies of the SWS is to be managed using the System Walkdown Program.
3-267 The staff's evaluation of the applicant's Sy stem Walkdown Program is documented in SER Section 3.0.3.1.9. The System Walkdown Program is consistent with the program described inGALL 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 from
 
bolting, 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 aging effect/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 Report
 
suggests 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 and Preventive Maintenance Program and the Instru ment 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.
The staff's evaluation of the applicant's Periodic Surveillance and Preventive Maintenance Program is documented in SER Section 3.0.3.3.5. The staff determines that the applicant's
 
Periodic Surveillance and Preventive Maintenanc e 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 from copper-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 SER Section 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 aging effect/mechanism, in a manner consistent with the GALL Report.
3-268 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, piping components, 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 Inspection Program, manages loss of material in stainless steel components.
The staff reviewed the applicant's Buried Piping Inspection Program and its evaluation is documented 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 m anage 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 the aging effect/mechanism, as recommended by the GALL Report.
3.3.2.1.18  Loss of Material Due to Pitting and Crevice Corrosion
 
For loss of material due to pitting and crevice corrosion of stainless steel piping, piping components, and piping elements exposed to s odium pentaborate solution, the GALL Report recommends programs consistent with GALL AMP XI.M2, "Water Chemistry" and GALLAMP 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 steel components is managed by the Water Chemis try 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 Inspection Program was not explicitly identified in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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-BWR Program and One-Time Inspecti on 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 provi des 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 aging effect/mechanism, as recommended by the GALL Report.
3.3.2.1.19  Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion 3-269 For loss of material due to pitting, crevice, and galvanic corrosion of copper alloy 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 3.3.1-31, the applicant stated that loss of material in copper alloy components 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 Inspection Program was not explicitly identified in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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 Inspecti on 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 provi des 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 aging effect/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 alloy piping, piping components, and piping elements exposed to fuel oil, the GALL Report
 
recommends programs consistent with GALL AMP XI.M30, "Fuel Oil Chemistry" and GALLAMP XI.M32, "One-Time Inspection."
In LRA Table 3.3.1, Item 3.3.1-32, the applicant stated that the Diesel Fuel Monitoring Program manages 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 Inspection Program was not explicitly identified in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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 Inspection Program. 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 allo y components is adequately managed by monitoring and controlling conditions that would cause this aging effect and by monitoring the effectiveness 3-270 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 the application 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 programsconsistent 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 3.3.1-33, the applicant stated that the Oil Analysis 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 Inspection Program was not explicitly identified in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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 to
 
lubricating 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 the application 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 piping elements 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 steel components 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 C hemistry 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.
3-271 During the audit and review, the staff confirmed that VYNPS meets these criteria. The staff finds that 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 is documented 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 elements
 
exposed to treated water greater than 140F. It is to be combined with the One-Time Inspection Program 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.
On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
3.3.2.1.23  Cracking Due to Stress Corrosion Cracking
 
For cracking due to SCC of stainless steel piping, piping components, and piping elements exposed to treated water greater than140F, the GALL Report recommends programs consistentwith 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-BWR Program, 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 veri fy the effectiveness of the Water Chemistry Program.During the audit and review, the staff asked the applicant for clarification on the basis of which items 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 boiler
 
and primary containment atmospheric control and containment air dilution system exposed to treated water greater than 140F using the its Water Chemistry Control -BWR Program and One-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 aging effect/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 oil system exposed to air - outdoor (external), the GALL Report recommends program consistentwith GALL AMP XI.M29, "Aboveground Steel Tanks Program."
3-272 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 Walk down Program and its evaluation is documented in 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 tan ks in diesel fuel oil systems exposed to outdoor air 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.
On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
 
3.3.2.1.25  Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting, and crevice corrosion of steel bolting and closure bolting 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 and closure 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 identified above, appropriately addressed the aging effect/mec hanism, 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 ex posed to closed cycle cooling water greater 3-273 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-Closed Cooling Water Program, manages cracking for stainless steel components.
During the audit and review, the applicant stated that for this aging effect, the One-Time Inspection Program will be explicitly identif ied in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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 and One-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 el ements, and heat exchanger components exposed to closed cycle cooling water greater than 140F 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 application identified 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, piping components, piping elements, tanks, and heat exchanger components exposed to closed cyclecooling 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 steel components of most auxiliary systems, the Wa ter Chemistry Control-Closed Cooling Water Program manages loss of material. Furthermore, the applicant stated that the Water Chemistry
 
Control-Auxiliary Systems Progr am 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-Time Inspection Program will be explicitly identif ied in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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 Chemis try Control-Auxiliary Systems Program. This evaluation 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-Au xiliary Systems Program. Therefore, the staff 3-274 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 aging effect/mechanism, as recommended by the GALL Report.
3.3.2.1.28  Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion
 
For loss of material due to general, pitting, crevice, and galvanic corrosion of steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to closed cyclecooling 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-Closed Cooling 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-Time Inspection Program will be explicitly identif ied in the system tables (Tables 3.3.
2.-1 2-1 through>3.3.2.-13 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 and 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. 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 application identified 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 heat exchanger components exposed to closed cycle c ooling water, the GALL Report recommends aprogram 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-Closed Cooling Water Program manages loss of material for stainless steel heat exchanger
 
components.
3-275 During the audit and review, the applicant stated that for managing this aging effect, the One-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.
2.-1 2-1>through 3.3.
2.-13 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 and 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. 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 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 application identified 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, piping components, 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-Closed Cooling Water Program manages loss of material for stainless steel components and that for
 
stainless steel components of the deminera lized water system, the Water Chemistry Control-Auxiliary Systems Progr am manages loss of material.
During the audit and review, the applicant stated that for managing this aging effect, the One-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.
2.-1 2-1>through 3.3.
2.-13 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 and 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. 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, and
 
piping elements exposed to closed cycle cooling water in a manner consistent with the GALL
 
Report and therefore acceptable.
3-276 During the audit and review, the staff asked the applicant to clarify why there were no items in LRA Table 3.3.2-13-12 being managed by the Wate r 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
 
referenced in LRA Table 3.3.2-13-12 managed by t he Water Chemistry Control-BWR Program is 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 Chemis try Control - BWR Program. The One-Time Inspection Program will be used to verify the e ffectiveness 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 application identified 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, piping components, piping elements, and heat exchanger components exposed to closed cycle coolingwater, 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-Closed Cooling Water Program manages loss of material for copper alloy components.
During the audit and review, the applicant stated that for managing this aging effect, the One-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.
2.-1 2-1>through 3.3.
2.-13 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 and 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. 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, piping
 
components, 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 application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
3-277 In LRA Table 3.3.1, Item 3.3.1-51, the applicant stated that, for copper alloy components of the house heating boiler system, demineralized water sy stem, and portions of the HVAC system, the Water Chemistry Control-Auxiliary Syst ems 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 Sy stems Program. The staff evaluations of these programs are documented in SER Section 3.0.3.3.7 and 3.0.3.1.6, respectively. The Water
 
Chemistry Control-Auxiliary Sy stems 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 aging effect/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 heat exchanger 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-Closed Cooling 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, the One-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.
2.-1 2-1>through 3.3.
2.-13 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 and 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 be adequately 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 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 c onfirm the effectiveness of the Water Chemistry Control - Closed Cooling Water Program. The staff' s evaluation of this exception is provided in 3-278 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.
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.
3.3.2.1.33  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 Report
 
recommends 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 Program manages 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 SER Section 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 aging effect/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 system piping, piping components, and piping elements exposed to internal condensation, the GALL
 
Report 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 Program manages loss of material for stainless steel components of auxiliary sy stem exposed to treated air.The staff's evaluation of the applicant's Instrument Air Quality Program is documented in SER Section 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 aging effect/mechanism, in a manner consistent with the GALL Report.
3-279 3.3.2.1.35  Increased Hardness, Shrinkage and Loss of Strength Due to Weathering For increased hardness, shrinkage and loss of strength due to weathering of elastomer fire barrier 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 the auxiliary 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 elastomer penetration 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 LRA Table 3.3.1, Item 3.3.1-61. The GALL Report's Line Item VII.G-1 is for component fire barrier penetration
 
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 managed by 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, LRA
 
Table 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 Line
 
Item 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 Structureand/orComponent/
CommodityIntendedFunctionMaterialEnvironmentAging EffectRequiringManagementAgingManagementProgram NUREG1801 Vol.2 ItemTable 1 Item N o t e s Penetration sealant (fire, flood, radiation)
EN, FB, FLB, PB, SNSElastomerProtected from weather Cracking, Change in material properties Fire Protection, Structures
 
Monitoring III.A6-1 2 (TP-7)3.5.1-44C 3-280b.Add line item:
Bulk Commodities Structureand/orComponent/
CommodityIntendedFunctionMaterialEnvironmentAging EffectRequiringManagementAgingManagementProgram NUREG1801 Vol.2 ItemTable 1 Item N o t e s Penetration sealant (fire)
EN, FB, PB, SNSElastomerProtected from weather Cracking, Change in material properties Fire Protection VII.G-1 (A-19)3.3.1-61Bc.Add line item:
Bulk Commodities Structureand/orComponent/
CommodityIntendedFunctionMaterialEnvironmentAging EffectRequiringManagementAgingManagementProgram NUREG1801 Vol.2 ItemTable 1 Item N o t e s Penetration sealant (flood, radiation)
EN, FLB, PB, SNSElastomerProtected from weather Cracking, Change in material properties Structures Monitoring III.A6-1 2 (TP-7)3.5.1-44C During the audit and review, the staff noted that in LRA Table 3.5.2-6 for elastomer seismic isolation joints in a protected from weat her 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-1
 
is 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 managed by the Fire Protection Program There 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 material properties. 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.
3-281 Because this discussion addresses seismic gaps and fire barrier seals, the applicant was asked to 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 a
 
Note 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 read as 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 Joints Bulk Commodities Structureand/orComponent/
CommodityIntendedFunctionMaterialEnvironmentAging EffectRequiringManagementAgingManagementProgram NUREG1801 Vol.2 ItemTable 1 Item N o t e s Seismic isolation jointSSRElastomerProtected from weather Cracking, Change in material properties Structures Monitoring III.A6-1 2 (TP-7)3.5.1-44C 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.
3.3.2.1.36  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 the auxiliary systems tables. Steel fire doors ar e 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 doors in 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 Report
 
Line Item VII.G-3 is for component fire rated doors. The applicant was asked to clarify why the
 
note is C, (different component but consistent with the GALL Report otherwise) for this AMR line 3-282 item, instead of Note B (consistent with the GALL Report, but AMP takes exceptions). In a letter dated 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 application identified 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-Influenced Corrosion, and Fouling For loss of material due to general, pitting, crevice, and MIC, and fouling of 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 3.3.1-68, the applicant stated that the loss of material in steel components exposed to raw or untreated water is managed by the Fire Water System Program.
The staff reviewed the applicant's Fire Water Sy stem Program and its evaluation is documented in 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 Program 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 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 the potable 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 the One-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 "untreated water" 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. Carbon steel is not
 
expected to experience significant aging effects in this treated water environment. The applicant 3-283 states that a One-Time Inspection of car bon 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 copper alloy 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 Surv eillance 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 st eel 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 acceptable because 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 the request 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 steel components 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-Time Inspection 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 2-1 through 3.3.
2.-13 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 rather than 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.
The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.11. This AMP is consistent, with exceptions and enhancements, with GALL 3-284AMP XI.M26, "Fire Protection." The staff determined it to be an acceptable method for management of loss of material from EDG stainl ess 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 application identified 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 Fouling For loss of material due to pitting, crevice, and MIC, and fouling of copper alloy piping, piping components, 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 alloy components 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 than the 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 pum
: p. 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 in SER 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 wa ter 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 the fire 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 the One-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.
The staff's evaluation of the applicant's Periodic Surveillance and Preventive Maintenance Program 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 3-285 Appendix A.1. The Periodic Surveillance and Pr eventive 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 changes identified above, appropriately addressed the agi ng 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, piping components, 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 steel components 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 Program is 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 aging effect/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 Drain Lines) Microbiologically-Influenced Corrosion In LRA Table 3.3.1, Item 3.3.1-72, the applicant stated that loss of material of steel component internal 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.
On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/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 the auxiliary systems tables. Steel crane structural girders are evaluated as structural components in 3-286 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 aging effect/mechanism, in a manner consistent with the GALL Report.
3.3.2.1.43  Loss of Material Due to General, Pitting, Crevice, Galvanic, and Microbiologically-Influenced Corrosion, and Fouling For loss of material due to general, pitting, crevice, galvanic, and MIC, and fouling of steel heat exchanger components exposed to raw water, the GALL Report recommends programsconsistent 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 is consistent with the GALL Report for most auxilia ry 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 SER Section 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 in SER 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.
On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/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 exchanger tubes exposed to raw water, the GALL Report recommends programs consistent with GALL AMP XI.M20, "Open-Cycle Cooling Water System."
3-287 In LRA Table 3.3.1, Item 3.3.1-83, the applicant stated that for the fire protection system, the Fire 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 of fouling 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 in SER 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 the fire 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 the aging 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 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).
The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience
 
and proposals for managing 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 Recommended Summary of Technical Information in the Amended Application. In LRA Section 3.3.2.2, the applicant 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:
3-288
* 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 and fouling
* 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 components Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant claimed 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.
3.3.2.2.1  Cumulative Fatigue Damage
 
LRA Section 3.3.2.2.1 states that fatigue 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 4.3 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 exchanger tubes 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 in 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 3-289 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 heat exchanger tubes exposed to treated water is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicant's Wa ter Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Progr am, 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 and One-Time Inspection
>Programs and determined that they are adequate to manage reduction of heat transfer due to
 
fouling in stainless steel heat exchanger tubes exposed to treated water. The staff finds this to be
>consistent with the criteria of SRP-LR Section 3.3.2.2.2 and therefore acceptable.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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).
3.3.2.2.3  Cracking Due to Stress Corrosion Cracking
 
The staff reviewed LRA Section 3.3.2.2.3 against the following SRP-LR Section 3.3.2.2.3 criteria:
  (1)LRA Section 3.3.2.2.3 addresses the cracking due to SCC, this aging effect is not applicable to VYNPS. Cracking due to SCC can occur in the stainless steel piping, piping
 
components, and piping elements of the BWR SLC system that are exposed to sodium
 
pentaborate solution greater than 140F. At VYNPS, the sodium pentaborate solution in the SLC system does not exceed 140F. Therefore cracking due to SCC is not an AERM for 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 stainless steel piping, piping components, and piping elements of the BWR SLC system that are
 
exposed to sodium pentaborate solution greater than 60 C (140 F). The existing AMP 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 ambient temperatures may exceed 140F, sodium pentaborate is not normally present in this portion 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.
3-290 On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS.  (2)LRA Section 3.3.2.2.3 addresses cracking of stainless steel heat exchanger components exposed 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 steel and 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-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 heat exchanger components exposed to treated water greater than 140F is an AERM at VYNPS. There are no auxiliary system co mponents at VYNPS with stainless steel cladding. For VYNPS auxiliary systems these stainless steel heat exchanger components are managed by the Water Chemistry Cont rol-BWR Program. This program monitors parameters and contaminants to ensure they re main 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 staff determines that the use of the applicant's One-Time Inspection Program in
>conjunction with its Water Chemistry Contro l-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
>therefore is acceptable.
 
  (3)LRA Section 3.3.2.2.3 addresses cracking of stainless steel diesel engine exhaust piping exposed to diesel exhaust due to SCC.
SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in stainless steel diesel engine exhaust piping, piping components, 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 cracking due to SCC in stainless steel diesel engine 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 Periodic Surveillance and Preventive Maintenance Progr am. 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 staff concludes 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 for cracking of stainless steel due to SCC when exposed to diesel exhaust.
>
3-291 The staff finds that this satisfies the criteria of SRP-LR Section 3.3.2.2.3 and is therefore
>acceptable.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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).
3.3.2.2.4  Cracking Due to Stress Corrosion Cracking and Cyclic Loading
 
The staff reviewed LRA Section 3.3.2.2.4 against the following SRP-LR Section 3.3.2.2.4 criteria:
  (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 occur in 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 primar y 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 finds that this aging effect is not applicable to VYNPS.  (2)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 occur in stainless steel PWR regenerative heat exchanger components exposed to treated
 
borated water greater than 60C (140 F). 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 regenerative heat exchanger exposed to treated borated water. This
 
item is not applicable to VYNPS.
3-292 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 this aging effect is not applicable to VYNPS.  (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 occur in the stainless steel pump casing for the PWR high-pressure pumps in the chemical and
 
volume control system. The existing AMP moni tors 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 finds that 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 3.3.2.2.5 criteria:
  (1)LRA Section 3.3.2.2.5 addresses cracking and change of material properties due to elastomer 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 elastomer degradation 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 to elastomer 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 Maint enance 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 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 for cracking and change of material properties due to elastomer
 
degradation in elastomer duct flexible connections of the HVAC systems exposed to air.
>
3-293 The staff finds that this satisfies the criteria of SRP-LR Section 3.3.2.2.5 and is therefore
>acceptable.  (2)LRA Section 3.3.2.2.5 addresses the hardening and loss of strength due to elastomer degradation, 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 elastomer degradation 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 that there 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 that VYNPS 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 sta ff concludes that the applicant's programs meet SRP-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 General Corrosion The 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 storage racks 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 of material 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 spent fuel storage racks exposed to a treated water environment. These aging effects are managed by
 
the Water Chemistry Control-BWR Program.
3-294 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-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 prev entive 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 and requires 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 sta ff concludes that the applicant's programs meet SRP-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 3.3.2.2.7 criteria:
  (1)LRA Section 3.3.2.2.7 addresses the loss of material of carbon steel piping and components 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 crevice corrosion may occur in steel piping, piping components, and piping elements, including
 
the tubing, valves, and tanks in the reacto r 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
 
corrosion does not occur. The GALL Report recommends further evaluation of programs
 
to manage loss of material due to general, pitting, and crevice corrosion, including 3-295 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 at VYNPS 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 preser ving 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 not sufficient in managing the loss of material of steel piping, piping components, and piping
 
elements, 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 reviewed the applicant's Oil Analysis and One-time Inspection Programs and
>determined that they are adequate to manage the loss of material of steel piping and
 
components in auxiliary sy stems exposed to lubricating oil. The staff finds that , based on
>the programs identified above, the applicant has met the criteria of SRP-LR
>Section 3.3.2.2.7.
Also, in the LRA, the applicant stated that VYNPS is a BWR with an inert containment atmosphere 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 finds
>that 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 components in other auxiliary systems exposed to tr eated 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 crevice corrosion may occur in steel piping, piping components, and piping elements in the BWR
 
RWCU 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 effectivene ss of the chemistry control program should be 3-296 verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage loss of ma terial 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 cooling system. Loss of material due to general, pitting, and crevice corrosion in carbon steel
 
piping and components in other auxiliary sy stems 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 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 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 3.2.2.7 and therefore is
>acceptable.
>The staff finds this to be consistent with the criteria of SRP-LR Section 3.3.2.2.7 and
>therefore acceptable.
>  (3)LRA Section 3.3.2.2.7 addresses the loss of material of carbon steel and stainless steel diesel exhaust piping and components exposed to diesel exhaust in the EDG and John
 
Deere 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, piping
 
components, 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), pitting and crevice corrosion for carbon steel and stainless steel diesel exhaust piping and
 
components exposed to diesel exhaust in the EDG and John Deere Diesel generator
 
systems is managed by the Periodic Surve illance 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
 
in the fire protection system are managed by the Fire Protection Program. The applicant's Fire Protection Program uses visual inspections of diesel exhaust piping and components
 
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.
3-297 The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program. The Periodic Surveillance and Pr eventive 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 adequately
 
managed.The staff also reviewed the applicant's Fire Protection Program and its evaluation is documented 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, with exceptions 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 the
>criteria of SRP-LR Section 3.3.2.2.7.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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-Influenced Corrosion The 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 or wrapping) 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
 
effects of loss of material from general, pitting, and crevice corrosion, and MIC. The
 
effectiveness of the buried piping and tanks inspection program should be verified to evaluate an
 
applicant's inspection frequency and operating experience with buried components, ensuring that
 
loss of material does not occur.
The applicant stated in the LRA that loss of material due to general, pitting, crevice, and MIC for carbon 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) prev entive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried
 
carbon steel components.
3-298 The applicant also stated that buried components are to 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 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 inspected within 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 sta ff concludes that the applicant's programs meet SRP-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-Influenced Corrosion and Fouling The staff reviewed LRA Section 3.3.2.2.9 against the following SRP-LR Section 3.3.2.2.9 criteria:
  (1)LRA Section 3.3.2.2.9 addresses the loss of material of carbon steel piping and components 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 crevice corrosion, MIC, and fouling may occur in steel piping, piping components, piping
 
elements, 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
 
programs 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 at VYNPS. 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 Pr ogram. 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 3-299 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 Program alone 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, the applicant 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 exchanger components 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 crevice corrosion, 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, MIC and fouling for carbon steel heat exchanger components exposed to lubricating oil are an
 
AERM in the auxiliary systems, and is m anaged by the Oil Analysis Program. This program includes periodic sampling and analysis of lubricating oil to maintain
 
contaminants within acceptable limits, t hereby preserving an environment that is not conducive to corrosion or fouling. Operati ng 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 the loss 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, reviewed the
>applicant's Oil Analysis and One-time Inspection Programs and determined that they are
 
adequate to manage the loss of material of steel heat exchanger components exposed to 3-300 lubricating oil. The staff finds that the applicant has met the criteria of SRP-LR
>Section 3.3.2.2.9.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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 3.3.2.2.10 criteria:  (1)LRA Section 3.3.2.2.10 addresses loss of material from steel piping with elastomer lining or stainless steel cladding due to pitting and crevice corrosion is not applicable to
 
VYNPS. 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 to
 
treated water and treated borated water if the cladding or lining is degraded. For the
 
auxiliary systems at VYNPS no credit is taken fo r 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 crevice corrosion 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.
The applicant was asked in RAI 3.3.1-22-K-01 to confirm that no auxiliary components have 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 to RAI 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 3-301 auxiliary systems exposed to treated wate r 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 because no credit is
>taken for elastomer linings or stainless steel cladding to prevent loss of material due to
 
pitting and crevice corrosion from steel piping. The staff also confirmed 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 finds that this aging effect is not applicable to VYNPS.
The staff finds that, based on the programs identified above, the applicant has met the criteria 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 and components 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 crevice corrosion may occur in stainless steel and aluminum piping, piping components, piping
 
elements, and for stainless steel and steel with stainless steel cladding heat exchanger
 
components 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 no aluminum components exposed to treated water. Loss of material due to pitting and
 
crevice corrosion for stainless steel piping and components, and for stainless steel heat
 
exchanger components exposed to treated wate r in the auxiliary systems at VYNPS 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 reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program. The use of the One-Time Inspection Program in conjunction with the
 
Water Chemistry Control-BWR Program pr ovides 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.
3-302 The staff finds that, based on the programs identified above, the applicant has met the criteria 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 components exposed to condensation (external) in t he 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 crevice corrosion may occur in copper alloy HVAC piping, piping components, and piping
 
elements 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 corrosion for copper alloy components exposed to condensation (external) in the HVAC and other
 
auxiliary systems is managed by the Sy stem Walkdown Program, the Periodic Surveillance and Preventive Maintenance Program , the Service Water Integrity Program, and the Heat Exchanger Monitoring Progr am. 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 AM R associated with copper alloy components 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 the criteria of SRP-LR Section 3.3.2.2.10.  (4)LRA Section 3.3.2.2.10 addresses the loss of material of copper alloy components exposed 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 crevice corrosion may 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 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.
3-303 The applicant stated in the LRA that loss of material due to pitting and crevice corrosion for copper alloy components exposed to lubric ating 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 ex perience 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 Analysis Program 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 met the 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, piping components, 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 crevice corrosion may occur in HVAC aluminum piping, piping components, and piping elements
 
and 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 corrosion could occur for HVAC aluminum piping, piping components, and piping elements and
 
stainless steel ducting and components exposed to condensation. At VYNPS, there are
 
no aluminum components or stainless steel ducting exposed to condensation in the
 
HVAC systems. However, this item can be applied to stainless steel components
 
exposed 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 Pr ogram, 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 steel components 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.
3-304 The staff finds that, based on the programs identified above, the applicant has met the criteria 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 protection system piping, piping components, and piping elements exposed to internal condensation due to pitting and crevice corrosion.
SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion 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 corrosion could occur for copper alloy fire protection system piping, piping components, and piping
 
elements 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 of material 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 alloy components 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.
The staff evaluated each auxiliary system AM R associated with copper alloy components exposed 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 the criteria of SRP-LR Section 3.3.2.2.10.
3-305  (7)LRA Section 3.3.2.2.10 addresses the loss of material of stainless steel piping, piping components, 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 crevice corrosion may occur in stainless steel piping, piping components, and piping elements
 
exposed 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 corrosion could occur for stainless steel piping, piping components, and piping elements exposed
 
to 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 excavated during 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 been inspected 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.
The staff finds that, based on the programs identified above, the applicant has met the criteria 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 and components 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 crevice corrosion may occur in stainless steel piping, piping components, and piping elements of
 
the 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 3-306 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 corrosion for 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 and therefore acceptable.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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 components exposed to treated water in the auxiliary and other systems due to pitting and crevice, and galvanic corrosion.
 
SRP-LR Section 3.3.2.2.11 states that loss of material due to pitting, crevice, and galvanic
 
corrosion may occur in copper alloy piping, piping components, and piping elements exposed to
 
treated 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 galvanic corrosion for copper alloy piping and components exposed to treated water in the auxiliary and
 
other systems is managed by the Water Chemis try 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 sta ff concludes that the applicant's programs meet SRP-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 3-307 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 3.3.2.2.12 criteria:  (1)LRA Section 3.3.2.2.12 addresses the loss of material of stainless steel, aluminum and copper 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 crevice corrosion, 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 corrosi on 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 in stainless steel, aluminum and copper alloy piping, and components exposed to fuel oil is
 
an 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
 
within the limits specified by the ASTM standards. Maintaining parameters within limits
 
ensures 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 sufficient in managing the loss of material of stainless steel, aluminum and copper alloy piping, and
 
components 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 the criteria 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 and components 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 crevice corrosion, and MIC may occur in stainless steel piping, piping components, and piping
 
elements exposed to lubricating oil. The existing program periodically samples and 3-308 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 in stainless 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 limit s, thereby preserving an environment that is not conducive to corrosion. Operating experi ence 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 of material 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.
The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.13.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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 not applicable 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 elastomer seals and components exposed to air-indoor uncontrolled (internal or external). The GALL 3-309 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 insufficient basis 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 two surfaces. 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, the
>staff finds that this aging effect is not applicable to VYNPS.
Based on the program identified above, the staff concludes that the applicant's program meets SRP-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 for PWR steel charging pump casings with stainless steel cladding exposed to treated borated
 
water. As VYNPS is a BWR and has no charging pumps. This item is not applicable to VYNPS SRP-LR Section 3.3.2.2.14 states that loss of material due to cladding breach may occur in PWR steel charging pump casings with stainless steel cladding exposed to treated borated water. 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 this aging effect is not applicable to VYNPS.
3.3.2.2.15  Quality Assurance for Agi ng Management of Nonsafey-Related Components SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.
3-310 Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for which the applicant has claimed consistency with the GALL Report, and for which the GALL
 
Report recommends further evaluation, the staff 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 Report Summary of Technical Information in the Application. 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 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 applicant indicated, via notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. 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 com ponent 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 in the 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 Su mmary of Aging Management Evaluation - LRA Table 3.3.2-1 The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for the SLC system component groups.
The staff finds that all AMR evaluation results in LRA Table 3.3.2-1 are consistent with the GALL Report.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).
3-311 3.3.2.3.2  Service Water Systems Summa ry of Aging Management Evaluation - LRA Table 3.3.2-2 The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for the SWSs component groups.
In LRA Table 3.3.2-2, the applicant proposed to manage loss of material due to wear of copper-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 is documented 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.
In LRA Table 3.3.2-2, the applicant proposed to manage loss of material from stainless steel valve bodies exposed to outdoor air us ing the System Walkdown Program.
The staff reviewed the applicant's System Walkdown Program, which entails inspections of external 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 externalsurfaces 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 adequatel y 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 Management Evaluation - LRA Table 3.3.2-3 The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for the RBCCW system component groups.
In LRA Table 3.3.2-3, the applicant proposed to manage loss of material due to wear of 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 using the Heat Exchanger Monitoring Program.
The staff reviewed the applicant's Heat Exc hanger Monitoring Program and its evaluation is documented in SER Section 3.0.3.3.1. Heat ex changer monitoring program will inspect the heat exchangers for degradation. Eddy current inspec tions 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.
>
3-312 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 Program
>On this basis, t. T he staff finds that management of loss of material due to wear in the RBCCW
>system is acceptable.
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).
3.3.2.3.4  Emergency Diesel Generator System Summary of Aging Management Evaluation-LRA Table 3.3.2-4 The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for the EDG system component groups.
In LRA Table 3.3.2-4, the applicant proposed to manage cracking of stainless steel strainers exposed 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 that maintains oil systems free of contaminants (prima rily 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>Since 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 steel expansion 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.
3-313 The staff reviewed the 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 that includes periodic inspections and tests that manage aging
 
effects not managed by other AMP s. The prev entive maintenance and surveillance testing activities are generally implemented through r epetitive 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 of copper-alloy heat exchanger tubes exposed to lubricating oil or treated water using the Service
 
Water Integrity Program.
The staff reviewed the Service Water Integrity Program and its evaluation is documented in SER Section 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 of copper-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 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 maint enance and surveillance testing activities are generally implemented through repetitive tasks or r outine 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 steel strainers exposed to outdoor air using the System Walkdown Program.
The staff reviewed the applicant's System Walkdown Program, which entails inspections of external 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 externalsurfaces 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 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).
3-314 3.3.2.3.5  Fuel Pool Cooling Systems Su mmary of Aging Management Evaluation -LRA Table 3.3.2-5 The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the fuel pool cooling systems component groups.
In LRA Table 3.3.2-5, the applicant proposed to manage cracking of aluminum/boron carbide material 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
 
periodically and controlled within established levels of contaminants, the aging effect of cracking
 
of 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 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).
3.3.2.3.6  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 the fuel oil system component groups.
In LRA Table 3.3.2-6, the applicant proposed to manage loss of material from carbon steel tanks exposed 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 the applicant'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 draining
 
and 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 hoses exposed 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.
3-315 The staff reviewed the applicant's Diesel Fuel Monitoring Program. The staff also reviewed the applicant'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 draining
 
and 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.
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).
3.3.2.3.7  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 the IA system component groups.
The staff determines that all AMR evaluation results in LRA Table 3.3.2-7 are consistent with the GALL Report.
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).
3.3.2.3.8  Fire Protection - Water System Summary of Aging Management Evaluation-LRA Table 3.3.2-8 The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the fire protection-water system component groups.
In LRA Table 3.3.2-8, the applicant proposed to manage cracking of 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 barrier inspection 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.
3-316 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 barrier inspection 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 determines that cracking due to
 
fatigue of 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 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 exchanger tubes exposed to treated water using the Fire Protection Program.
The staff reviewed the applicant's Fire Protection Program, which includes a fire barrier inspection 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 Tthe staff finds that management of fouling in the fire protection system is
>acceptable.
In LRA Table 3.3.2-8, the applicant proposed to manage 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 using the Fire Protection Program.
The staff reviewed the applicant's Fire Protection Program, which includes a fire barrier inspection 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 hous ing, heat exchanger shell, piping, pump casing, and valve bodies; copper-alloy heat exchanger tubes, tubing, and valve bodies; as well as 3-317 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 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 using the Fire Water System Program.The staff reviewed the applicant's Fire Water Sy stem Program and its evaluation is documented in 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 va lve 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 flow nozzles 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 of components 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 steel bolting 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 of external 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 and
 
copper 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 AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL 3-318 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).
3.3.2.3.9  Fire Protection - CO 2 System Summary of Aging Management Evaluation - LRA Table 3.3.2-9 The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the fire protection - CO 2 system component groups.
In LRA Table 3.3.2-9, the applicant proposed to manage loss of material from copper alloy piping, tubing, and valve bodies and stainless steel bolting, orifices, tubing, and valve bodies
 
exposed to outdoor air using the System Walkdown Program.
The staff reviewed the applicant's System Walkdown Program, which entails inspections of external 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 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).
3.3.2.3.10  Heating, Ventilation, and Air C onditioning Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-10 The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations for the HVAC systems component groups.
In LRA Table 3.3.2-10, the applicant proposed to manage fouling of copper alloy heat exchanger tubes exposed to condensation using the Periodic Surveillance and Preventive Maintenance
 
Program.The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance 3-319 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 prev entive maintenance and surveillance testing activities are generally implemented through r epetitive tasks or routine monitoring of plant operations. 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 exchanger fins 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 is documented 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 copper alloy 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 Program and 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 prev entive maintenance and surveillance testing activities are generally implemented through r epetitive 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 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 is documented 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 aluminum damper, fan, and louver housings; copper-alloy tubing and valve bodies; and stainless steel
 
bolting exposed to outdoor air using the System Walkdown Program.
3-320 The staff reviewed the applicant's System Walk down Program and its evaluation is documented in SER Section 3.0.3.1.9. The System Walkdow n 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 fr om 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 heat exchanger tubes exposed to steam using the Wa ter 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-Au xiliary Systems Program.
The staff reviewed the applicant's Water Chemis try Control Program for auxiliary systems and the 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 Chem istry 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 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).
3.3.2.3.11  Primary Containment Atmosphere Control and Containment Atmosphere Dilution Systems Summary of Aging Managem ent Evaluation-LRA Table 3.3.2-11 The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for the PCAC and containment atmosphere dilution systems component groups.
3-321 In LRA Table 3.3.2-11, the applicant proposed to manage fouling of stainless steel heat exchangers exposed to indoor air using the Pe riodic Surveillance and Preventive Maintenance Program.The staff reviewed the Periodic Surveillance and Preventive Maintenance Program and. 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 Periodic Surv eillance and Preventive Maintenance Program visually inspect external surfaces of t he 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 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).
3.3.2.3.12  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 for the John Deere diesel component groups.
In LRA Table 3.3.2-12, the applicant proposed to manage cracking due to fatigue of stainless steel expansion joints and the carbon steel piping, silencer, and turbocharger exposed to
 
exhaust gases using the Periodic Surve illance and Preventive Maintenance Program.
The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program and 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 prev entive maintenance and surveillance testing activities are generally implemented through r epetitive tasks or routine monitoring of plant operations.
Because>Since 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, t T he staff finds that management of cracking in the John Deere Diesel is
>acceptable.
In LRA Table 3.3.2-12, the applicant proposed to manage fouling of a copper-alloy radiator exposed to indoor air using the Periodic Su rveillance and Preventive Maintenance Program.
3-322 The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program and 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 prev entive maintenance and surveillance testing activities are generally implemented through r epetitive 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 and heat 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, which manages 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 evaluati on 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 Syst ems Program augmented by the O ne-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-alloy radiator and heat exchanger tubes and the carbon steel heater housings, piping, and pump
 
casings exposed to treated water using the Water Chemistry Control-Aux iliary Systems Program, and the One-Time Inspection Program.
The staff reviewed the applicant's Water Chemistry Control Program for auxiliary systems, which manages 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 Chem istry Control Program-Auxiliary Systems Program augmented by the One-Time Inspection Program.
3-323 In LRA Table 3.3.2-12, the applicant proposed to manage loss of material due to wear of the copper-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 maint enance 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 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).
3.3.2.3.13  Augmented Offgas System, Nonsafet y-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-1 The staff reviewed LRA Table 3.3.2-13-1, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.14  Condensate System, Nonsafety-Re lated Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-2 The staff reviewed LRA Table 3.3.2-13-2, which summarizes the results of AMR evaluations for the condensate system component groups.
In LRA Table 3.3.2-13-2, the applicant proposed to manage cracking-fatigue from carbon steel heat exchanger (shell) exposed to 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 is documented 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 3-324AMP 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 adequately managed 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 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).
3.3.2.3.15  Containment Air Dilution, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-3 The staff reviewed LRA Table 3.3.2-13-3, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.16  Condensate Demineralizer System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-4 The staff reviewed LRA Table 3.3.2-13-4, which summarized the results of AMR evaluations for the condensate demineralizer system component gr oups. 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 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).
3.3.2.3.17  Control Rod Drive System, Nonsaf ety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-5 The staff reviewed LRA Table 3.3.2-13-5, which summarized the results of AMR evaluations for the 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.
3-325 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).
3.3.2.3.18  Core Spray System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-6 The staff reviewed LRA Table 3.3.2-13-6, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.19  Condensate Storage and Transfer System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-7 The staff reviewed LRA Table 3.3.2-13-7, which summarizes the results of AMR evaluations for the 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-alloy tubing and stainless steel bolting exposed to out door air using the System Walkdown Program.
The staff reviewed the applicant's System Walk down Program and its evaluation is documented in SER Section 3.0.3.1.9. The System Walk down 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 m anaged 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 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 3-326 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).
3.3.2.3.20  RWCU Filter Demineralizer System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-8 The staff reviewed LRA Table 3.3.2-13-8, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.21  Circulating Water System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-9 The staff reviewed LRA Table 3.3.2-13-9, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.22  Diesel Generator and Auxiliaries, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-10 The staff reviewed LRA Table 3.3.2-13-10, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.23  Diesel Lube Oil System, Nonsafet y-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-13-11 The staff reviewed LRA Table 3.3.2-13-11, which summarized the results of AMR evaluations for the diesel lube oil system component groups. The st aff finds that all AMR evaluation results in LRA Table 3.3.2-13-11 are consistent with the GALL Report.
3-327 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).
3.3.2.3.24  Demineralized Water System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-12 The staff reviewed LRA Table 3.3.2-13-12, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.25  Feedwater System, Nonsafety-Re lated Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-13 In LRA Table 3.3.2-13-13, the applicant proposed to manage cracking-fatigue from carbon steel heat 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 is documented 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 is adequately 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 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).
3.3.2.3.26  Fuel Oil System, Nonsafety-Relat ed Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-14 The staff reviewed LRA Table 3.3.2-13-14, which summarized the results of AMR evaluations for the fuel oil system component groups. The staff fi nds that all AMR evaluation results in LRA Table 3.3.2-13-14 are consistent with the GALL Report.
3-328 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).
3.3.2.3.27  Fire Protection System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-15 The staff reviewed LRA Table 3.3.2-13-15, which summarized the results of AMR evaluations for the fire protection system component groups.
In LRA Table 3.3.2-13-15, the applicant proposed to manage loss of material from copper-alloy tubing and stainless steel bolting exposed to out door air using the System Walkdown Program.
The staff reviewed the applicant's System Walkdown Program, which entails inspections of external 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 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).
3.3.2.3.28  Fuel Pool Cooling System, Nonsaf ety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-16 The staff reviewed LRA Table 3.3.2-13-16, which summarized the results of AMR evaluations for the 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 AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL 3-329 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 Components Affecting Safety-Related Systems Summa ry of Aging Management Evaluation-LRA Table 3.3.2-13-17 The staff reviewed LRA Table 3.3.2-13-17, which summarized the results of AMR evaluations for the fuel pool cooling filter demineralizer syst em 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 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).
3.3.2.3.30  House Heating Boiler System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-18 The staff reviewed LRA Table 3.3.2-13-18, which summarized the results of AMR evaluations for the house heating boiler system component groups.
In LRA Table 3.3.2-13-18, the applicant proposed to manage loss of material from carbon steel heat 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 c onfirm the effectiveness of the Water Chemistry Control-Auxiliary Systems Program.
The staff reviewed the applicant's Water Chemistry Control Program for auxiliary systems, which manages 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 evaluat ion of these program 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 carbon steel piping, steam traps and valve bodies exposed to steam is adequately managed using the Water
 
Chemistry Control Program-Aux iliary 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 steel heat exchanger (shell) exposed to steam greater than 220 F using the One-Time Inspection Program.The staff reviewed the applicant's One-Time Inspection Program and its evaluation is documented 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 3-330 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 using the 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 boiler
>system is acceptable.
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).
3.3.2.3.31  Hydraulic Control Units, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-19 The staff reviewed LRA Table 3.3.2-13-19, which summarized the results of AMR evaluations for the 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 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).
 
3.3.2.3.32  High Pressure Coolant Injection System, Nonsafety-Related Components Affecting
 
Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-20 The staff reviewed LRA Table 3.3.2-13-20, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.33  Heating, Ventilation, and Air Conditioning Systems, Nonsafety-Related Components Affecting Safety-Related Systems Summa ry of Aging Management Evaluation-LRA Table 3.3.2-13-21 3-331 The staff reviewed LRA Table 3.3.2-13-21, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.34  Instrument Air System, Nonsafet y-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-22 The staff reviewed LRA Table 3.3.2-13-22, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.35  MG Lube Oil System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-23 The staff reviewed LRA Table 3.3.2-13-23, which summarized the results of AMR evaluations for the 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.
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).
3.3.2.3.36  Nitrogen System, Nonsafety-Relat ed Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-24 The staff reviewed LRA Table 3.3.2-13-24, which summarized the results of AMR evaluations for the 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 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).
3-332 3.3.2.3.37  Nuclear Boiler System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-25 The staff reviewed LRA Table 3.3.2-13-25, which summarized the results of AMR evaluations for the nuclear boiler system component groups. The st aff 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 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).
3.3.2.3.38  Neutron Monitoring System, Nonsaf ety-related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-26 The staff reviewed LRA Table 3.3.2-13-26, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.39  Post-Accident Sampling System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-27 The staff reviewed LRA Table 3.3.2-13-27, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.40  Primary Containment Atmosphere Control System, Nonsafety-Related Components Affecting Safety-Related Systems Summa ry of Aging Management Evaluation-LRA Table 3.3.2-13-28 The staff reviewed LRA Table 3.3.2-13-28, which summarized the results of AMR evaluations for the 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 AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL 3-333 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-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-29 The staff reviewed LRA Table 3.3.2-13-29, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.42  Reactor Building Closed Cooling Water System, Nonsafety-Related Components Affecting Safety-Related Systems Summa ry of Aging Management Evaluation-LRA Table 3.3.2-13-30 The staff reviewed LRA Table 3.3.2-13-30, which summarized the results of AMR evaluations for the 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.
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).
3.3.2.3.43  Reactor Core Isolation Cooling System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-31 The staff reviewed LRA Table 3.3.2-13-31, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.44  Radwaste, Liquid and Solid, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-32 3-334 The staff reviewed LRA Table 3.3.2-13-32, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.45  Residual Heat Removal System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-33 The staff reviewed LRA Table 3.3.2-13-33, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.46  RHR Service Water System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-34 The staff reviewed LRA Table 3.3.2-13-34, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.47  Equipment Retired in Place, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-35 The staff reviewed LRA Table 3.3.2-13-35, which summarized the results of AMR evaluations for the 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 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).
3-335 3.3.2.3.48  Reactor Water Clean-Up System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-36 The staff reviewed LRA Table 3.3.2-13-36, which summarized the results of AMR evaluations for the reactor water clean-up system component gr oups. 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 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).
3.3.2.3.49  Standby Fuel Pool Cooling Syst em, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-37 The staff reviewed LRA Table 3.3.2-13-37, which summarized the results of AMR evaluations for the 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.
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).
3.3.2.3.50  Standby Gas Treatment System , Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-38 The staff reviewed LRA Table 3.3.2-13-38, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.51  Stator Cooling System, Nonsafet y-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-39 The staff reviewed LRA Table 3.3.2-13-39, which summarized the results of AMR evaluations for the stator cooling system component groups. The st aff finds that all AMR evaluation results in LRA Table 3.3.2-13-39 are consistent with the GALL Report.
3-336 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).
3.3.2.3.52  Standby Liquid Control System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-40 The staff reviewed LRA Table 3.3.2-13-40, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.53  Sampling System, Nonsafety-Relat ed Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-41 The staff reviewed LRA Table 3.3.2-13-41, which summarized the results of AMR evaluations for the sampling system component groups. The staff fi nds 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 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).
3.3.2.3.54  Service Water System, Nonsafet y-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-42 The staff reviewed LRA Table 3.3.2-13-42, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.55  HD & HV Instruments System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-43 3-337 The staff reviewed LRA Table 3.3.2-13-43, which summarized the results of AMR evaluations for the HD 7 HV Instruments System component gr oups. 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 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).
3.3.2.3.56  Air Evacuation System, Nonsafet y-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-44 The staff reviewed LRA Table 3.3.2-13-44, which summarized the results of AMR evaluations for the air evacuation system component groups. The st aff finds that all AMR evaluation results in LRA Table 3.3.2-13-44 are consistent with the GALL Report.
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).
3.3.2.3.57  Auxiliary System, Nonsafety-Rela ted Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-45 In LRA Table 3.3.2-13-45, the applicant proposed to manage cracking-fatigue from carbon steel heat exchanger (shell) exposed to 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 is documented 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 adequately managed 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 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).
3-338 3.3.2.3.58  Buildings (drainage system com ponents) System, Nonsafety-Related Components Affecting Safety-Related Systems Summa ry of Aging Management Evaluation-LRA Table 3.3.2-13-46 The staff reviewed LRA Table 3.3.2-13-46, which summarized the results of AMR evaluations for the buildings system component groups. The staff fi nds 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 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).
3.3.2.3.59  Circulating Water Priming System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-47 The staff reviewed LRA Table 3.3.2-13-47, which summarized the results of AMR evaluations for the buildings system component groups. The staff fi nds 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 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).
3.3.2.3.60  Extraction Steam System, Nonsafet y-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-48 In LRA Table 3.3.2-13-48, the applicant proposed to manage cracking due to fatigue for stainless steel expansion joints exposed to steam or treated water greater than 270F using metal 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 co mponents 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 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).
3.3.2.3.61  Heater Drain System, Nonsafet y-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-49 3-339 The staff reviewed LRA Table 3.3.2-13-49, which summarized the results of AMR evaluations for the 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 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).
 
3.3.2.3.62  Heater Vents System, Nonsafet y-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-50 The staff reviewed LRA Table 3.3.2-13-50, which summarized the results of AMR evaluations for the heater vents system component groups. The sta ff 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 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).
3.3.2.3.63  Hydrogen Water Chemistry System , Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-51 The staff reviewed LRA Table 3.3.2-13-51, which summarized the results of AMR evaluations for the hydrogen water chemistry system component gr oups. 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 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).
3.3.2.3.64  Main Steam System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-52 In LRA Table 3.3.2-13-52, the applicant proposed to manage cracking-fatigue from carbon steel heat exchanger (shell) exposed to steam greater than 270 F using the One-Time Inspection Program.The staff reviewed the applicant's One-Time Inspection Program and its evaluation is documented 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." >
3-340 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 using the One-Time Inspection Program. On this basis, the staff finds that management of cracking-fatigue in the main steam
 
system is acceptable.
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).
3.3.2.3.65  Make-up Demineralizer System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-53 The staff reviewed LRA Table 3.3.2-13-53, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.66  Service Air System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-54 The staff reviewed LRA Table 3.3.2-13-54, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.67  Seal Oil System, Nonsafety-Rela ted Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-55 The staff reviewed LRA Table 3.3.2-13-55, which summarized the results of AMR evaluations for the seal oil system component groups. The staff fi nds 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 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).
3-341 3.3.2.3.68  Turbine Building Closed Cooling Water System, Nonsafety-Related Components Affecting Safety-Related Systems Summa ry of Aging Management Evaluation-LRA Table 3.3.2-13-56 The staff reviewed LRA Table 3.3.2-13-56, which summarized the results of AMR evaluations for the 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 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).
3.3.2.3.69  Main Turbine Generator System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Agi ng Management Evaluation-LRA Table 3.3.2-13-57 In LRA Table 3.3.2-13-57, the applicant proposed to manage cracking-fatigue from carbon steel pump and turbine casing exposed to steam and treated water greater than 270 F using the One-Time Inspection Program.
The staff reviewed the applicant's One-Time Inspection Program and its evaluation is documented 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 is adequately 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 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).
3.3.2.3.70  Turbine Lube Oil System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-58 The staff reviewed LRA Table 3.3.2-13-58, which summarized the results of AMR evaluations for the turbine lube oil system component groups. The st aff 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 AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL 3-342 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).
3.3.2.3.71  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 management evaluations for the auxiliary syst ems evaluated in the GALL Report.
In LRA Table 3.3.1, Item 3.3.1-10 discussion column, the applicant stated that high strength steel bolting is not used in the auxiliary systems.
The staff confirmed that there is no high str ength steel bolting in the VYNPS auxiliary systems.
On the basis that there is no high strength steel bolting in the auxiliary systems at VYNPS, the staff finds that this aging effect is not applicable at VYNPS.
In LRA Table 3.3.1, Item 3.3.1-36, the applicant stated that the reduction of neutron-absorbing capacity 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 in the 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 BWR spent fuel storage racks exposed to treated water greater than 60C (greater than140F) due to SCC is not applicable at VYNPS.
The staff confirmed that the temperature of the water to which spent fuel racks are exposed is limited 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 applicable at VYNPS.In LRA Table 3.3.1, Item 3.3.1-41, the applicant stated that the 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.
The staff confirmed that VYNPS auxiliary system s 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 because the 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."
3-343 During the audit and review, the staff asked the applicant to clarify how aging of steel closure 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 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 because the 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 system closure 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 t hat all auxiliary system bolting within the scope of 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 with the 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 closure bolting exposed to air due to thermal effects, gasket creep, and self-loosening is not applicable
 
at VYNPS.During the audit and review, the staff confirm ed that no auxiliary system closure bolting is subjected 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.
3-344 In LRA Table 3.3.1, Item 3.3.1-62, the applicant stated that loss of material due to pitting and crevice corrosion of aluminum piping, pipi ng components, and piping elements exposed to raw water 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 us ed for auxiliary systems SCs within the scope of license renewal at VYNPS. On the basis that alum inum 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 because loss 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 components exposed 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 because concrete 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 because concrete 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 because loss 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.
3-345 In LRA Table 3.3.1, Item 3.3.1-74, the applicant stated that this line item was not used because loss 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 as structural 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 manner consistent 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 strength due 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 untreated water in the auxiliary systems that require aging management. On the basis that there are no elastomeric components in the auxiliary system s 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 and crevice corrosion of stainless steel and copper alloy piping, piping components, and piping
 
elements 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 SSCs within 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, piping
 
components, 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.
3-346 In LRA Table 3.3.1, Item 3.3.1-80, the applicant stated that the loss of material of stainless steel and 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 piping elements 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 because loss 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 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 3.3.1-92, the applicant stated that galvanized steel surfaces are evaluated as steel for the auxiliary systems at VYNPS.
On the basis that galvanized steel surfaces are evaluated as steel for the auxiliary systems, the staff 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 system components exposed to controlled indoor air at VYNPS.
On the basis that there is no auxiliary system components exposed to controlled indoor air in the auxiliary 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 as an 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 to
 
dried 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 3.3.2-1 through 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 aging effects 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 for component types of various materials exposed to indoor air. This includes a flame arrestor in the
 
fuel oil system fabricated from aluminum; tubi ng in the fire protection water system made of copper alloy; and nozzles, piping, tubing, siren or valve bodies in the fire protection system made
 
of copper alloy. Similarly, the applicant finds no aging effects for stainless steel nozzles, tubing, 3-347 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 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. Aluminum has
 
an excellent resistance to corrosion when exposed to humid air (an uncontrolled indoor
 
environment). The aluminum oxi de 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 exhibits 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 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 environment exhibits 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 dry
 
atmospheres 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 fabricated from aluminum, copper alloy, or stainless steel exposed to air.
The applicant identified no aging effects for a PACCAD system stainless steel diaphragms exposed to silicone.
The GALL Report identified that stainless steels are highly resistant to corrosion in dry atmospheres in the absence of corrosive species.
On this basis, and considering that silicone does not react with stainless steel, the staff finds that there are no AERM for stainless steel diaphragms of the PACCAD system exposed to silicone.
The applicant also identified no aging effects for stainless steel bolting in the CW system exposed 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 3-348 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 external 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. 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 to condensation.
The GALL Report identified that glass in a raw water environment exhibits no aging effect and 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 HVAC system sight glass exposed to condensation.
The applicant also identified no aging effects for an SLC system sight glass exposed to sodium pentaborate solution.
The GALL Report identified that glass in a borated water environment exhibits no aging effect and 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 sight glass 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, and found 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.
On the basis that fiberglass (comprising glass and polymers) is similarly resistant to chemical attack 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.
3-349 The GALL Report identified that glass in a raw water environment exhibits no aging effect, and found 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 aging effects/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 exposed to interstitial fluid.
The applicant also identified no aging effects for fiberglass flexible duct connections exposed to indoor air.
For other non-metallic components, the applicant considered degradation from sustained vibratory 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 air
 
conditioning 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 two surfaces. 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.
On the basis of its review, the staff finds that wear is precluded by the system design feature and 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 evaluated the AMR results involving material, environment, AERM, and AMP combinations that are not 3-350 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 Conclusion====
The staff concludes that the applicant has provided sufficient information to demonstrate that the effects of aging for the auxiliary systems co mponents 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 Systems This section of the SER documents the staff's review of the applicant's AMR results for the
 
steam and power conversion system s components and component groups of:
* auxiliary steam
* condensate
* main steam
* 101 (main steam, extraction st eam, and auxiliary steam instruments)3.4.1  Summary of Technical Information in the Application LRA Section 3.4 provides AMR results for t he steam and power conver sion systems components and component groups. LRA Table 3.4.1, "Summary of Aging Management Evaluations for the
 
Steam and Power Conversion System," is a summa ry comparison of the applicant's AMRs with those evaluated in the GALL Report for the steam and power conver sion systems components and component groups.
The applicant's AMRs evaluated and incorporated applicable plant-specific and industry operating 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====
Evaluation The staff reviewed LRA Section 3.4 to determine whether the applicant provided sufficient information 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 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 AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters
 
described in the GALL Report; however, the staff did verify that the material presented in the
 
LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The 3-351 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 which further 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 ensure that 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, and AMPs 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 in the GALL ReportComponent Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP 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)
Steel piping, piping components, and piping
 
elements exposed to
 
steam (3.4.1-2)Loss of material due to general, pitting
 
and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection 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 3.4.2.2.2)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-352 Steel heat exchanger components
 
exposed to treated water
 
(3.4.1-3)Loss of material due to general, pitting
 
and crevice
 
corrosion Water Chemistryand One-Time
 
InspectionNoneNot applicable to BWRs Steel piping, piping components, and piping
 
elements exposed to treated water
 
(3.4.1-4)Loss of material due to general, pitting
 
and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection 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 3.4.2.2.2)
Steel heat exchanger components
 
exposed to treated water
 
(3.4.1-5)Loss of material due to general, pitting, crevice, and
 
galvanic corrosion Water 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 corrosion Water 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
 
corrosion Lubricating OilAnalysis and One-Time InspectionNoneNot applicable (See SER Section 3.4.2.2.2)
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)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-353 Stainless steel and copper alloy heat
 
exchanger tubes exposed
 
to treated water (3.4.1-9)Reduction of heat transfer due to
 
fouling Water Chemistryand One-Time
 
Inspection 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 3.4.2.2.4)
Steel, stainless steel, and copper alloy heat
 
exchanger tubes exposed
 
to lubricating
 
oil (3.4.1-10)
Reduction of heat transfer due to
 
fouling Lubricating 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 heat exchanger components
 
exposed to
 
lubricating oil
 
(3.4.1-12)
Loss of material due to general, pitting, crevice, and MIC Lubricating OilAnalysis and One-Time InspectionNoneNot applicable (See SER Section 3.4.2.2.5)
Stainless steel piping, piping
 
components, piping elements exposed to
 
steam (3.4.1-13)
Cracking due to SCC Water Chemistryand One-Time
 
Inspection 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 3.4.2.2.6)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-354 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 SCC Water 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
 
corrosion Water Chemistryand One-Time
 
Inspection 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 3.4.2.2.7)
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
 
corrosion Water 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)
Copper alloy piping, piping
 
components, and piping
 
elements exposed to
 
lubricating oil
 
(3.4.1-18)
Loss of material due to pitting and crevice
 
corrosion Lubricating OilAnalysis and One-Time InspectionNoneNot applicable (See SER Section 3.4.2.2.7)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-355 Stainless steel piping, piping
 
components, piping elements, and
 
heat exchanger components
 
exposed to
 
lubricating oil
 
(3.4.1-19)
Loss of material due to pitting, crevice, and MIC Lubricating OilAnalysis and One-Time InspectionNoneNot applicable (See SER Section 3.4.2.2.8)
Steel tanks exposed to air
- outdoor (external)
 
(3.4.1-20)
Loss of material/
general, pitting, and
 
crevice corrosion Aboveground 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 with GALL Report. (See
 
SER Section 3.4.2.1.6)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-356 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 heat exchanger 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 System Water Chemistry Control-Closed Cooling Water
 
Program (B.1.30.3)Consistent with GALL 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 due to 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)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-357 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 corrosion External Surfaces MonitoringSystem Walkdown Program (B.1.28)Consistent with GALL 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-Accelerated CorrosionFlow-Accelerated Corrosion Program (B.1.13)Consistent with GALL 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 with GALL Report (See
 
SER Section 3.4.2.1.9)
Steel heat exchanger 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 Periodic Surveillance and
 
Preventive
 
Maintenance
 
Program (B.1.22)Consistent with GALL Report (See
 
SER Section 3.4.2.1.10)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-358 Stainless steel and copper alloy piping, piping components, and piping
 
elements exposed to raw water (3.4.1-32)
Loss of material due to pitting, crevice, and MICOpen-Cycle CoolingWater System Periodic Surveillance and
 
Preventive
 
Maintenance
 
Program (B.1.22)Consistent with GALL 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 due to 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 due to selective leaching Selective Leaching of 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)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-359Gray cast iron piping, piping
 
components, and piping
 
elements exposed to
 
soil, treated water, or raw water (3.4.1-36)
Loss of material due to selective leaching Selective Leaching of 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 with GALL Report (See
 
SER Section 3.4.2.1.12)
Steel bolting and external
 
surfaces exposed to air with borated water leakage
 
(3.4.1-38)
Loss of material due to boric acid
 
corrosionBoric Acid CorrosionNoneNot applicable to BWRs Stainless steel piping, piping
 
components, and piping
 
elements exposed to
 
steam (3.4.1-39)
Cracking due to SCCWater ChemistryNoneNot applicable to BWRs Glass 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.)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-360 Stainless steel, copper alloy, and
 
nickel alloy
 
piping, piping
 
components, and piping
 
elements exposed to
 
air-indoor
 
uncontrolled (external)
 
(3.4.1-41)NoneNoneNoneConsistent with GALL 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 c onversion systems component groups followed any one 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 3-361 consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to manage 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 Report Summary of Technical Information in the Application. LRA Section 3.4.2.1 identifies the materials, environments, AERMs, and the following programs that manage aging effects for the
 
steam and power conver sion systems components:
* Flow-Accelerated Corrosion Program
* System Walkdown Program
* Water Chemistry Control - BWR Program
* Water Chemistry Control - Closed Cooling Water Program LRA Table 3.4.2-1 summarizes AMRs for the steam and power conver sion systems components and indicates AMRs claimed to be consistent with the GALL Report.
Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant claimed 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 the information 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 consistent with 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.
3-362 Note D indicates that the component for the AMR line item, although different from, is consistent with 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 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 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-BWR Program, augmented by the One-Time Inspection Pr ogram, to verify program effectiveness, will be used to manage loss of material for steel co mponents 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 Inspection Program 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-Time Inspection 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-BWR Program, augmented by the One-Time Inspection Pr ogram, to verify program effectiveness, will be used to manage loss of material for steel piping, piping components, and piping elements
 
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.
3-363 During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program 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-Time Inspection 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-BWR Program, augmented by the One-Time Inspection Pr ogram 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 conver sion 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 Inspection Program 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-Time Inspection 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 aging effect/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-BWR Program, augmented by the One-Time Inspection Pr ogram to verify program effectiveness, will be used to manage cracking due to SCC for stainless steel components exposed to steam.
3-364 During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program 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-Time Inspection 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 aging effect/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-BWR Program, augmented by the One-Time Inspection Pr ogram 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 Inspection Program 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-Time Inspection 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 aging effect/mechanism, as recommended by the GALL Report.
3-365 3.4.2.1.6  Loss of Material Due to General, Pitting, and Crevice Corrosion and Loss of Preload Due to Thermal Effects, Gasket Creep and Self-Loosening In the discussion column of LRA Table 3.4.1, Item 3.4.1-22, the applicant stated that its System Walkdown 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 System Walkdown 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 staff reviewed 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 bolting exposed 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 aging effect/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 is consistent 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 Walk down Program and its evaluation is documented in 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.
3-366 On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
3.4.2.1.8  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 is consistent 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 is documented 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-Accelerated Corrosion 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 is consistent 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 su rfaces, 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 Progr am. 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 the System 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 add enhancements to the program's implementing proc edure. Specifically, the applicant committed in Commitment #24 and Commitment #35, to have:
(1) the System Walkdown guidance document enhanced to perform periodic system engineer inspec tions 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 subjec t 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 Pr ogram a process to document biennial refresher training of Engineers to demonstrate inclusion of the methodology for aging management of plant
 
equipment as described in EPRI Aging Assessment Field Guide or comparable instructional
 
guide.
3-367 With this change, the applicant's management of steel components internally exposed to outdoor air or condensation will be consistent with the GALL Report and therefore acceptable to the staff.
The staff reviewed the applicant's System Walk down Program and its evaluation is documented in 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 aging effect/mechanism, as recommended by the GALL Report.
3.4.2.1.10  Loss of Material Due to General, Pitting, Crevice, Galvanic, and Microbiologically-Influenced Corrosion and Fouling For loss of material due to fouling and general, pitting, crevice, galvanic, and MIC in steel heat exchanger components exposed to raw water; the GALL Report recommends programsconsistent 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 for components of the CW system, its Periodic Su rveillance 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 Program and 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 prev entive maintenance and surveillance testing activities are generally implemented through r epetitive 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 LRA Tables 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 aging effect/mechanism, as recommended by the GALL Report.
3.4.2.1.11  Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion 3-368 In the discussion column of LRA Table 3.4.1, Item 3.4.1-32, the applicant stated that its Periodic Surveillance 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 and Preventive Maintenance Program and its evaluati on 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 GALL
 
Report and therefore acceptable to the staff.
On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
3.4.2.1.12  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 Water Chemistry Control - BWR Program will be used to manage loss of material in stainless steel and
 
steel components in its steam and power conversi on systems. The applicant further states that there are no nickel alloy components exposed to steam in the steam and power conversionsystems.The staff reviewed the applicant's Water Chemistry Control - BWR Program and its evaluation is documented 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, and nickel-based alloy piping, piping components, and piping elements exposed to steam; the GALL
 
Report recommends programs consistent with GALL AMP XI.M2, "Water Chemistry."
In the discussion column of LRA Table 3.4.1, Item 3.4.1-37, the applicant stated that its Water Chemistry 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 components exposed to steam from the applicant's house heating boiler system.
3-369 During the audit and review, the staff noted that for this aging effect, the GALL Report's recommended Water Chemistry Control-Auxiliary Sy stems 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 Progr am and its evaluation is documented in SER Section 3.0.3.3.7 The applicant's Water Chemistry Control-Aux iliary 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 components exposed to steam is adequately managed using the Wa ter Chemistry Control-Auxiliary Systems Program.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-Aux iliary Systems Program.
On the basis of its review, the staff finds that 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. The staff 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 Recommended Summary of Information in the Application. In LRA Section 3.4.2.2, the applicant further evaluates 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
* 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 3-370
* quality assurance for aging management of nonsafety-related components Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant claimed 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. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the
 
staff's review of the applicant's evaluation of this TLAA.
3.4.2.2.2  Loss of Material Due to General, Pitting, and Crevice Corrosion
 
The staff reviewed LRA Section 3.4.2.2.2 against the following SRP-LR Section 3.4.2.2.2 criteria:
  (1)LRA Section 3.4.2.2.2 addresses the loss of material of carbon steel piping and components 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 crevice corrosion may occur in steel piping, piping components, piping elements, tanks, and heat
 
exchanger components exposed to treated water and for steel piping, piping components, and piping elements exposed to steam. The exis ting 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 crevice corrosion 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
 
Chemistry Control-BWR Program will be confir med 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.
3-371  (2)LRA Section 3.4.2.2.2 addresses the loss of material of steel piping and components in steam and power conversion sy stems 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 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 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 carbon steel 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 finds that this aging effect is not applicable to VYNPS.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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-Influenced Corrosion and Fouling The 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, and fouling. 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 elements
 
exposed to raw water.
SRP-LR Section 3.4.2.2.3 states that loss of material due to general, pitting, and crevice corrosion, and MIC and fouling may occur in steel piping, piping components, and piping
 
elements 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 c onversion systems at VYNPS have no carbon steel components with intended functions that are exposed to raw water, therefore, this item is not
 
applicable to VYNPS.
3-372 On the basis that VYNPS does not have any components from this group, the staff finds that this aging 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 3.4.2.2.4 criteria:
  (1)LRA Section 3.4.2.2.4 addresses the reduction of heat transfer of stainless steel and copper 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 occur in 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 occur for 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 Pr ogram 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.  (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 occur in 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.
3-373 The staff finds that 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, 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 this aging effect is not applicable to VYNPS.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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-Influenced Corrosion The staff reviewed LRA Section 3.4.2.2.5 against the following SRP-LR Section 3.4.2.2.5 criteria:
  (1)LRA Section 3.4.2.2.5 addresses the loss of material due to general, pitting, crevice corrosion, 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 crevice corrosion, 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.
The staff finds that the steam and power conversion systems at VYNPS have no carbon steel 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 finds that 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, crevice corrosion, 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 crevice corrosion, 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 3-374 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 heat exchanger 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 finds that 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 due to 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 piping elements exposed to steam. The existing AMP moni tors 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.
In LRA Table 3.4.1, Item 3.4.1-14 discussion column, the applicant stated that the cracking due to SCC of stainless steel piping, piping components, tanks, and heat exchanger components
 
exposed 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 fi nds 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 exposed to steam is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicant's Water Chemistry Control-BWR Pr ogram 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 sta ff concludes that the applicant's programs meet SRP-LR Section 3.4.2.2.6 criteria. For those line items that apply to LRA Section 3.4.2.2.6, the 3-375 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 3.4.2.2.7 criteria:
  (1)LRA Section 3.4.2.2.7 addresses the loss of material of copper alloy components exposed 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 corrosion may occur in stainless steel, aluminum, and copper alloy piping, piping components, and
 
piping 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 corrosion for 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 effectivene ss 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 3.4.2.2.7 and is therefore acceptable.  (2)LRA Section 3.4.2.2.7 addresses loss of material due to pitting and crevice corrosion of stainless 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 corrosion may occur in stainless steel piping, piping components, and piping elements 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 finds that the steam and power conversion systems at VYNPS have no stainless 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 finds that this aging effect is not applicable to VYNPS.
3-376  (3)LRA Section 3.4.2.2.7 addresses the loss of material due to pitting and crevice corrosion of 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 corrosion may 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 copper alloy 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 finds that this aging effect is not applicable to VYNPS.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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 stainless steel piping, piping components, piping el ements, and heat exchanger components exposed to lubricating oil.
SRP-LR Section 3.4.2.2.8 states that loss of material due to pitting and crevice corrosion, and MIC may occur in stainless steel piping, piping components, piping elements, and heat
 
exchanger components exposed to lubricating o il. 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 3-377 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 conv ersion systems at VYNPS have no stainless steel 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 finds that this aging 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, and galvanic 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, and galvanic 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 be verified to
 
ensure that corrosion does not occur. The GALL Report recommends further evaluation of
 
programs to verify the effectiveness of water c hemistry 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 c onversion systems at VYNPS have no steel heat exchanger 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 this aging 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 the staff found acceptable.3.4.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Table 3.4.2-1, 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 3.4.2.3.
3-378 In LRA Table 3.4.2-1, the applicant indicated, via notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the
 
GALL Report. The applicant provided further in formation 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, materi al, 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 in the 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.
3.4.2.3.1  Main Condenser and MSIV Leakage Pathway Summary of Aging Management Evaluation-LRA Table 3.4.2-1 The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for the main condenser and MSIV leakage pathway component groups.
In LRA Table 3.4.2-1, the applicant proposed to manage cracking-fatigue of condenser components (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 management evaluations for the steam and power conver sion 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 of steel 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 high strength steel closure bolting exposed to air with steam or water leakage due to cyclic loading
 
and 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 sta ff finds that, for this component type, this aging effect is not applicable to VYNPS.
3-379 In LRA Table 3.4.1, Item 3.4.1-23 discussion column, the applicant stated that the cracking of stainless steel piping, piping components, and piping elements exposed to closed cycle cooling
 
water greater than60C (greater than140F) due to SCC is not applicable at VYNPS. The staff determined, 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 of material 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.
In LRA Table 3.4.1, Item 3.4.1-26 discussion column, the applicant stated that the loss of material of copper alloy piping, piping components, and piping elements exposed to closed-cycle
 
cooling 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 of heat 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 tha t, 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 of material 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 of heat 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 of material of copper alloy greater than15 percent Zinc piping, piping components, and piping 3-380 elements 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 of material 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 tha t, for this component type, this aging effect is not applicable at VYNPS.
3.4.2.3.3  Steam and Power Conversion Systems AMR Line Items That Have No Aging Effects-LRA Table 3.4.2-1 The 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 the main condenser and MSIV leakage pathway component groups.
In LRA Table 3.4.2-1, the applicant proposed to verify the integrity of the following condenser components 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 270F 3-381 On the basis of its review, the staff finds that above environment and material combinations, if managed 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 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).
 
====3.4.3 Conclusion====
The staff concludes that the applicant has provided sufficient information to demonstrate that the effects of aging for the steam and power conv ersion 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 Supports This 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 Application LRA 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 industry operating 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====
Evaluation The staff reviewed LRA Section 3.5 to determine whether the applicant provided sufficient information to demonstrate that the effects of aging for the SC supports components within the 3-382 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 AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters
 
described in the GALL Report; however, the staff did verify that the material presented in the
 
LRA was applicable and that the applicant 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.
In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations
 
were consistent with the 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 ensure that 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, and AMPs 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 GALLReportAMP in LRAStaff Evaluation BWR Concrete and Steel (Mark I, II, and III) Containments Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-383 Concrete 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.)
Concrete elements; All (3.5.1-2)Cracks and distortion due to
 
increased stress
 
levels from
 
settlement Structures Monitoring 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 Structures Monitoring 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.)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-384 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-specific AMP is to be
 
evaluatedNoneNot applicable.(VYNPS containment
 
is a Mark I steel
 
containment.)
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
 
corrosion ISI (IWE) and10 CFR 50, Appendix J Containment Inservice 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
 
corrosion ISI (IWE) and10 CFR 50, Appendix JNoneNot applicable.(VYNPS containment
 
is a Mark I steel
 
containment.)
Prestressed containment
 
tendons (3.5.1-7)Loss of prestress due 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 stainless steel elements: vent
 
line, vent header, vent line bellows; downcomers;
 
(3.5.1-8)Cumulative fatigue damage (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")
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-385 Steel, stainless steel elements, dissimilar metal welds:
 
penetration sleeves, penetration bellows;
 
suppression pool
 
shell, unbraced downcomers
 
(3.5.1-9)Cumulative fatigue damage (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)
Stainless steel penetration sleeves, penetration bellows, dissimilar metal welds (3.5.1-10)
Cracking due to SCC ISI (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 SCC ISI (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 loading ISI (IWE) and10 CFR 50, Appendix J, and
 
supplemented to
 
detect fine cracks Containment Inservice 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 loading ISI (IWE) and10 CFR 50, Appendix J, and
 
supplemented to
 
detect fine cracks Containment Inservice 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")
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-386 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-thaw ISI (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.)
Concrete elements:walls, dome, basemat, ring girder, buttresses, containment, concrete fill-in
 
annulus (as applicable).
 
(3.5.1-15)
Cracking due to expansion and reaction with
 
aggregate; increase in porosity, permeability due to
 
leaching of calcium hydroxide ISI (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, and moisture 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 J Containment Inservice Inspection
 
Program (B.1.15.1);
 
Containment Leak
 
Rate Program (B.1.8)Consistent with the GALL 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 penetration sleeves and
 
dissimilar metal welds; personnel
 
airlock, equipment
 
hatch and CRD
 
hatch (3.5.1-18)
Loss of material due to general, pitting, and crevice
 
corrosion ISI (IWE) and10 CFR 50, Appendix J Containment Inservice Inspection
 
Program (B.1.15.1);
 
Containment Leak
 
Rate Program (B.1.8)Consistent with GALL 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 SCC ISI (IWE) and10 CFR 50, Appendix JNoneNot applicable. (The VYNPS suppression
 
chamber is carbon
 
steel.)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-387 Steel elements:
suppression
 
chamber liner (interior surface)
 
(3.5.1-20)
Loss of material due to general, pitting, and crevice
 
corrosion ISI (IWE) and10 CFR 50, Appendix JNoneNot applicable. (The VYNPS 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)
Prestressed containment:
 
tendons and
 
anchorage components
 
(3.5.1-22)
Loss of material due to corrosionISI (IWL)NoneNot applicable.(VYNPS containment is a
 
Mark I steel containment without
 
prestressed
 
tendons.)Safety-Related and Other Structures; and Component Supports All Groups except Group 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 Structures Monitoring Program 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 of Structures
 
Not Covered by
 
Structures
 
Monitoring
 
Program," item 1)
All Groups except Group 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 Structures Monitoring Program 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 2
)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-388 All Groups except Group 6: steel
 
components: all
 
structural steel
 
(3.5.1-25)
Loss of material due to corrosion Structures Monitoring 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)
All Groups except Group 6: accessible
 
and inaccessible
 
concrete: foundation
 
(3.5.1-26)
Loss of material (spalling, scaling)
 
and cracking due to
 
freeze-thaw Structures Monitoring 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 except Group 6: accessible
 
and inaccessible interior/exterior
 
concrete (3.5.1-27)
Cracking due to expansion due to reaction with
 
aggregates Structures Monitoring 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 Structures Monitoring 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)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-389 Groups 1-3, 5-9:
foundation
 
(3.5.1-29)
Reduction in foundation strength, cracking, differential
 
settlement due to
 
erosion of porous
 
concrete subfoundation Structures Monitoring 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)
Group 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 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 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 Structures Monitoring Program
 
for accessible areas.
 
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 withGALL Report, which
 
recommends further
 
evaluation (See
 
SER Section 3.5.2.2.2
 
under the heading, "Aging Management
 
of Inaccessible
 
Areas")
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-390 Groups 1-5:
concrete (3.5.1-33)
Reduction of strength and
 
modulus due to
 
elevated temperature A plant-specific AMP 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")
Group 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 of Water-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: exterior above and below
 
grade concrete
 
foundation
 
(3.5.1-35)
Loss of material (spalling, scaling)
 
and cracking due to
 
freeze-thaw Inspection of Water-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).
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 2
)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-391 Group 6: all accessible/
 
inaccessible
 
reinforced concrete
 
(3.5.1-36)
Cracking due to expansion/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: exterior above and below
 
grade reinforced
 
concrete foundation
 
interior slab
 
(3.5.1-37)
Increase in porosityand permeability, loss of strength due
 
to leaching of calcium hydroxide For 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 to SCC; loss of
 
material due to
 
pitting and crevice
 
corrosion A plant-specific AMP 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 Structures Monitoring Program 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 Supports Not Covered by the
 
Structures Monitoring
 
Program")
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-392 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 Structures Monitoring Program 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 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 Structures Monitoring 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 fatigue damage (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 the GALL 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)
Structures Monitoring Program Structures Monitoring Program (B.1.27.2)Consistent with the GALL Report.
(See SER Section 3.5.2.1.10)
Group 6: exterior above and below
 
grade concrete
 
foundation; interior
 
slab (3.5.1-45)
Loss of material due to abrasion, cavitation Inspection of Water-Control
 
Structures Associated with Nuclear Power
 
PlantsNoneConsistent with the GALL Report.
(See SER Section 3.5.2.1.11)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-393Group 5: Fuel pool liners (3.5.1-46)
Cracking due to SCC; loss of
 
material due to
 
pitting and crevice
 
corrosion Water 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 the GALL 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 of Water-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 of Water-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
 
corrosion Water Chemistryand ISI (IWF)
Water ChemistryControl-BWR (B.1.30.2); Inservice
 
Inspection Program (B.1.15.2)Consistent with the GALL 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 Structures Monitoring Program Structures Monitoring Program (B.1.27.2)Consistent with the GALL Report.
(See SER Section 3.5.2.1.14)
Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-394 Group B1.1: highstrength low-alloy
 
bolts (3.5.1-51)
Cracking due to SCC; 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 Structures Monitoring 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 the GALL 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 GALLReportAMP in LRAStaff Evaluation 3-395 Steel, 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 Acid CorrosionNoneNot applicable to BWRs Groups 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 the GALL 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 the GALL Report.
(See SER Section 3.5.2.1)
The staff's review of the SC supports component groups followed any one of several approaches. 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.
3-3963.5.2.1  AMR Results Consistent with the GALL Report Summary of Technical Information in the Application. LRA Section 3.5.2.1 identifies the materials, 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 Program LRA Tables 3.5.2-1 through 3.5.2-6 summarize AMRs for the SC supports components and indicate AMRs claimed to be consistent with the GALL Report.
Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant claimed 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 the information 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 consistent with 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 3-397 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 consistent with 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 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 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, pitting and crevice corrosion of the carbon steel drywell head, drywell shell, drywell sump liner, drywell
 
to torus vent system, torus manway, torus ri ng girder, torus shell, and torus thermowell is managed using its Containment Inservice Ins pection Program and the Containment Leak Rate Program.During the audit and review, the staff noted that the applicant's Containment Inservice Inspection Program is a plant-specific program.
The staff reviewed the applicant's Containment In service Inspection Program. This evaluation is 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 3-398Code, 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 aging effect/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 the component 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 LRA Table 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 this revision to the LRA 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 for penetration 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 the carbon steel primary containment mechanical penetrations (includes those with bellows) is
 
managed using the Containment Inservice Ins pection Program and the Containment Leak Rate Program.During the audit and review, the staff noted that the applicant's Containment Inservice Inspection Program is a plant-specific program.
The staff reviewed the applicant's Containment In service Inspection Program and its evaluation is 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 Inspecti on Program is an acceptable AMP for managing cracking of the primary containment mechanical penetrations (includes those with bellows).
3-399 For cracking due to cyclic loading of steel, stainless steel and dissimilar metal welds for torus, vent line, vent header, vent line bellows and dow ncomers exposed to indoor uncontrolled air, theGALL 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 the stainless steel drywell to torus vent line be llows 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 Inspection Program is a plant-specific program.
The staff reviewed the applicant's Containment In service Inspection Program and its evaluation is 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 for
 
managing cracking of the drywell to torus vent line bellows.
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 3.5.2-1 (page 3.5-50), for component 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 no
 
license renewal intended function. These components are not safety-related and are not required
 
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 LRA Table 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.
3-400 The staff reviewed the applicant's response and finds it this revision to the LRA 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 Joint Seals, 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 the containment 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 the component drywell floor liner seal, the AMP s hown 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 whether included in accordance with the umbrella of the Structures Monitoring Program or in accordance
 
with the umbrella of the Containment Inservic e 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.
In a letter dated July 14, 2006, the applicant revised its LRA. Specifically, the applicant stated that aging effects on the drywell moisture barrier will be managed in accordance with the
 
Containment Inservice Inspection Program inst ead 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 aging management program from "Structures Monitori ng" 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.
3-401  (2)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)."  (3)In LRA Table 3.5.1, Line 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 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, 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.
The staff reviewed the applicant's response and finds it this revision to the LRA 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 applicant stated: 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, the
 
AMP shown for this line item is Periodic Su rveillance and Preventive Maintenance Program. LRA Table 3.5.1, Item 3.5.1-16 relates to primary containment seals and gaskets. The applicant has
 
stated 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, tw o 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 1
 
structures seals and gaskets would probably be the Periodic Surveillance and Preventive
 
Maintenance Program.
3-402 The applicant's staff stated that LRA Table 3.5.2-6 line item "Seals and gaskets-" on page 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 Preventive Maintenance 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 item for 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 Prev entive 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, rubber and 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 to deterioration 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.
The staff reviewed the applicant's Containment In service Inspection Program and its evaluation is 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 the same 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, rubber and 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."
3-403 The staff noted that for cracking and change in material properties due to deterioration of the elastomer 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 RateProgram 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 is documented 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 is consistent 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 aging effect/mechanism, as recommended by the GALL Report.
3.5.2.1.5  Loss of Leak Tightness in Closed Position Due to Mechanical Wear of Locks, Hinges and Closure Mechanisms In the LRA Table 3.5.1, Item 3.5.1-17, the applicant stated that locks, hinges, and closure mechanisms 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 active components 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 re ceived 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).
3-404 The staff reviewed the Peach Bottom and Millstone SERs which verify that locks, hinges, and other 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 metal welds) 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 Containm ent Inservice Inspection Program, which is a plant-specific AMP, and the Containment Leak Rate Program.
The staff reviewed the applicant's Containment In service Inspection Program and its evaluation is 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 Inservice Inspection Program is an acceptable management pr ogram 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 experience has 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 fo r 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 experience documentation 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 3-405 Inservice Inspection-IWE Program and the C ontainment 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 sy stem) 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 aging effect/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."
During the audit and review, the staff noted that loss of material of carbon steel damper framing exposed 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 in SER 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 VYNPS License 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 in accordance 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 GALLAMP XI.S6.
On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/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."
3-406 During the audit and review, the staff noted that loss of material of carbon steel fire hose reels exposed to a protected from weather environm ent is managed using the Fire Water System Program (with exceptions to the GALL Report and enhancements).
The staff reviewed the applicant's Fire Water Sy stem Program evaluation is documented in SER Section 3.0.3.2.12. The Fire Water System Program applies to water-based fire protection
 
systems that consist of sprinklers, nozzles, fitti ngs, 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 (including fire 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 aging effect/mechanism, as recommended by the GALL Report.
3.5.2.1.9  Cracking Due to Restraint Shrinkage, Creep, and Aggressive Environment
 
For cracking due to restraint shrinkage, creep and aggressive environment of concrete block masonry 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 for Vernon 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 a VYNPS 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 the regulatory 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 aging effect/mechanism, as recommended by the GALL Report.
3-407 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), for component 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 Monito ring 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 is E, different
 
AMP than shown in the GALL Report. However, the GALL Report Line Item III.A6-12 and 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), for component 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.
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 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 this revision to the LRA 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 and below 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 exterior walls 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 us ing the Structures Monitoring Program (withenhancements) 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.
3-408 On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/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 the Vernon Dam external walls above/below grade ex posed 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.
During the audit and review, the staff finds that inspections of the Vernon Dam are not part of a VYNPS 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 the regulatory 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 aging effect/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 structural members 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 envir onment; 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 (withenhancements) instead of the recommended GALL AMP XI.S7.
3-409 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.
On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/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 for the 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, "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 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 a VYNPS 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 the regulatory 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 aging effect/mechanism, as recommended by the GALL Report.
3.5.2.1.13  Loss of Material/General, Pitting and Crevice Corrosion 3-410 For loss of material due to general, pitting and crevice corrosion of stainless steel and steel support 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 stainless steel anchorage/embedments exposed to a flui d environment is managed using the Water Chemistry Control-BWR Program and the Inservic e Inspection Program, which is a plant-specificAMP instead of the GALL AMP XI.S3.
The staff reviewed the applicant's Inservice Inspection Program and its evaluation is documented 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 same requirements 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 aging effect/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 and crevice corrosion of Groups B2 and B4 galvanized steel, aluminum, and stainless steel
 
components 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 an
 
outdoor 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 galvanized steel, aluminum, and stainless steel VYNPS components which are within the scope of license renewal
 
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 crevice corrosion of aluminum and stainless steel components in an outdoor environment is not applicable if the atmospheric environment is non-aggressive. The ambient environment at 3-411 VYNPS is not chemically polluted by vapors of sulfur dioxide (SO
: 2) or other similar substances and 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 experienc e and by previously approved staff positions documented in the Joseph M. Farley SER (NUREG-1825, page 3-314).
The applicant stated that the components that may be considered in the B2 and B4 grouping consists 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 or aluminum components in outdoor air. The ambi ent environment at VYNPS is not chemically polluted by vapors of SO 2 or other similar substances and the external environment does not contain saltwater or high chlorides. Therefore, loss of material due to pitting and crevice
 
corrosion is not an AERM for aluminum and stai nless steel components exposed to the external environment.
The applicant stated that the AMR results for galvanized steel components in outdoor air should indicate 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 M onitoring Program. This evaluation is documented 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/mec hanism, 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), for component 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 as identified 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 letter dated
 
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 transmission
 
towers with a material of galvanized steel in an exposed to weather environment. The staff
 
review the applicant's response and finds it this revision to the LRA 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.
3-412 During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-71), for component 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.
During interviews with the applicant's technical personnel, the applicant's staff stated that as identified 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 letter dated
 
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 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 aging effect/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), for component conduit support, material galvanized st eel 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 as identified 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 letter
 
dated 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
 
support 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 aging effect/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), for component 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 as identified 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 letter dated
 
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 for
 
electrical and instrument panels and enclosures with a material of galvanized steel in an exposed
 
to weather environment.
3-413 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 3.5.2-6 (page 3.5-78), for component structural bolting, material galvani zed 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 as identified 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 letter
 
dated 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 structural
 
bolting 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 aging effect/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, bolted connections; 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 support assembly, 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 anc horage/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 is documented 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 same requirements 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.
3-414 For loss of material due to general and pitting corrosion of carbon steel vent header support exposed 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 air
 
or 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, and
 
the 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 that since 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. The
 
applicant has also revised this AMR line item to reflect this change. The staff reviewed the
 
applicant's response and determined it this revision to the LRA 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 aging effect/mechanism, as recommended by the GALL Report.
3.5.2.1.16  None (Galvanized Steel and Al uminum Support Members; Welds; Bolted Connections; 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), for component 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; 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 the GALL 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 LRA Table 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 th e response is revision to
>the LRA acceptable and the applicant appropriately addressed the aging effect/mechanism, as
>recommended by the GALL Report.
3-415 During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-73), for component 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 following
 
components: 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 unlike the 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 th e response is revision to
>the LRA acceptable and 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. The staff 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 Recommended Summary of Information in the Application. In LRA Section 3.5.2.2, the applicant further evaluates aging management, as recommended by the GALL Report, for the SC supports components and provides information concerni ng 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 of foundation 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 elevated temperature
* loss of material due to general, pitting, and crevice corrosion
* loss of prestress due to relaxation, shrinkage, creep, and elevated temperature 3-416
* 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 porosity and 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 elevated temperature
* 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 applicant claimed 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, which address several areas:
Aging of Inaccessible Concrete Areas. The staff reviewed LRA Section 3.5.2.2.1.1 against the criteria 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 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 inaccessible 3-417 areas of PWR and BWR concrete and steel containments. The existing program relies on ASMECode, 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 containment located 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 entrainment In addition, as stated in the LRA, VYNPS concrete also meets requirements of later ACI guide ACI 201.2R-77, "Guide to Durable Concrete," since both documents use the same ASTM
 
standards for selection, application and testing of concrete.
Furthermore, as stated in the LRA, 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 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 standing steel 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 this aging effect is not applicable to VYNPS.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet
>SRP-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).
3-418 Cracks and Distortion Due to Increased Stress 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. The staff reviewed LRA Section 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 increased stress 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 from settlement 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 located within 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 increased stress 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 to increased stress levels from settlement; reduction of foundation strength, cracking and
 
differential settlement due to erosion of porous concrete subfoundations are not plausible aging
 
effects due to the nonexistence of these aging mechanisms at VYNPS. The staff finds that these 3-419 aging 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 this aging effect is not applicable to VYNPS.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet
>SRP-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. The>staff 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 of concrete 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 to elevated 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, specifies
 
the 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 tem perature 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 on radiant 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 CC indicates 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 temperature limits. 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 and modulus 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 3-420 aging effect mechanisms are not applicable to the VYNPS Mark I free standing steel containment. 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 the VYNPS containment.
On the basis that VYNPS 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 sta ff concludes that the applicant's programs meet
>SRP-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 LRA Section 3.5.2.2.1.4 against the criteria in SRP-LR Section 3.5.2.2.1.4.
In LRA Section 3.5.2.2.1.4, the applicant addressed the loss of material of steel elements of accessible 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 crevice corrosion may occur in steel elements of accessible and inaccessible areas for all types of PWR
 
and 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 of accessible 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. The
 
concrete 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.
3-421 The applicant also stated that to prevent corrosion of the lower part of the drywell shell, the interior 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 for inaccessible 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 reactor
 
building 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 applicant stated that:
The drywell steel where the drywell shell is embedded is inspected in accordance with 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 asked the 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 becomes embedded 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 LRA Table 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 becomes embedded 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.
3-422 On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report.
Based on the programs identified above, the staff concludes that the applicant's meet SRP-LR Section 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 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 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 this aging effect is not applicable to VYNPS.
Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.6 states fatigue analyses of suppression pool 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 are evaluated and documented in Section 4.6.
3-423 The components associated with LRA Table 3.5.1, Item 3.5.1-9 are:
penetration sleeves, penetration bellows; suppression pool shell, unbraced downcomers.
The applicant was asked to explain how LRA Table 3.5.1, Item 3.5.1-9 was not applicable when a 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 LRA Table 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 it was 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 dated July 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 vent system 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 as follows: 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 in Section 4. Fatigue TLAAs for the torus and associated penetrations are evaluated
 
and documented in Section 4.6.
3-424 LRA Section 3.5.2.3, Time-Limited Aging Analyses, is revised to read as follows:
TLAA identified for structural components and commodities include fatigue analyses 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 aging effect/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-LR Section 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 is not applicable to VYNPS.
SRP-LR Section 3.5.2.2.1.7 states that cracking due to SCC of stainless steel penetration sleeves, 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 appropr iate examinations/evaluations implemented 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 not applicable 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 and a corrosive environment exist. The stresses may be applied (external) or residual (internal). The
 
normal environment inside the drywell is dr
: y. 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 and bellows 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 stainless steel 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.
3-425 During the audit and review, the applicant was asked to explain if the VYNPS Containment Inservice 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 inspections
>and 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 staff finds that this aging effect is not applicable to VYNPS.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet
>SRP-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 criteria
>in 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, penetration bellows, 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 steel and stainless steel shells (including welded joints) and penetrations (including penetration
 
sleeves, 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 existingprogram 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 penetrations is a TLAA which is evaluated as documented in LRA Section 4.6.
3-426 In the discussion column of LRA Table 3.5.1, Items 3.5.1-12 and 3.5.1-13, the applicant did not make 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 is revised as follows:    (1)For clarification, the discussion column of VYNPS Table 3.5.1, Line Items 3.5.1-12 and 3.5.1-13 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 steel penetration 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.
The staff finds this revision to the LRA acceptable.
Based on the programs identified above, staff
>concludes that the applicant's programs meet the SRP-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 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 (Scaling, Cracking, and Spalling) Due to Freeze-Thaw. The staff reviewed LRA Section 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.
3-427 SRP-LR Section 3.5.2.2.1.9 states that loss of material (scaling, cracking, and spalling) due to freeze-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 this aging effect is not applicable to VYNPS.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet
>SRP-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 and
>Permeability Due to Leaching of Calcium Hydroxide. The staff reviewed LRA Section 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 and reaction 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 aggregate and 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 with aggregate, 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
 
not required because VYNPS containment concrete (basemat) is designed in accordance with 3-428 specification 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 this aging effect is not applicable to VYNPS.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet
>SRP-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, which address several areas:
Aging of Structures Not Covered by Structures Monitoring Program. The staff reviewed LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1.
In LRA Section 3.5.2.2.2.1, the applicant addresses the aging of structures not covered by the Structures Monitoring Program.
SRP-LR Section 3.5.2.2.2.1 states that the GALL Report recommends further evaluation of certain structure-aging effect combinations 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.
The staff finds that the applicant has included the eight SRP-LR Section 3.5.2.2.2.1 structure/aging effect combinations in its Structures Monitoring Program and no further
 
evaluation is required as recommended by the GALL Report. However, although not required, 3-429 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 of Embedded Steel for Groups 1-5, 7, 9 Structures The staff reviewed item 1 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 this aging effect is not applicable to VYNPS. The aging mechanisms 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 groundw ater. 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 hi gh 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 to corrosion 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 program s identified above, the applicant has met the criteria of
>SRP-LR Section 3.5.2.2.2.1 for further evaluation.  (2)Increase in Porosity and Permeability, Cracking, Loss of Material (Spalling, Scaling) Due to Aggressive Chemical Attack for Groups 1-5, 7, 9 Structures The staff reviewed item 2 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. Aggressive chemical attack becomes significant to c oncrete 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 an
 
acceptable degree of protection against aggressive chemical attack. Water chemical analysis
 
results 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, 3-430 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 program s identified above, the applicant has met the criteria of
>SRP-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-LR Section 3.5.2.2.2.1.
The applicant stated, in the LRA, that this aging effect is applicable to VYNPS. The Structures Monitoring 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 an aging 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 of SRP-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-LR Section 3.5.2.2.2.1.
The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Aggregates were 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.
The staff finds that the loss of material (spalling, scaling) and cracking due to freeze-thaw for Groups 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.
3-431 In the discussion column of LRA Table 3.5.1, Item 3.5.1-26, the applicant stated that freeze-thaw is 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 that VYNPS 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 guide ACI 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 falls
 
outside 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 of SRP-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. 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 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.
The staff finds through discussions with the applicant's technical personnel that cracking due to expansion 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 showing that inaccessible areas concrete was constructed in accordance with the recommendations in
 
ACI 201.2R-77.
3-432 During interviews with the applicant's technical personnel, the applicant's staff stated that for construction of concrete, VYNPS site specific ation, as documented in the Audit and Review Report, identifies the same ASTM standards for achieving durable concrete as those specified
 
in ACI 201.2R-77.
The staff finds that, based on the program s identified above, the applicant has met the criteria of
>SRP-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-LR Section 3.5.2.2.2.1.
The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Class 1 structures 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 for Groups 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 this aging effect is not applicable to VYNPS.  (7)Reduction in Foundation Strength, Cracking, Differential Settlement Due to Erosion of Porous Concrete Subfoundation for Groups 1-3, 5-9 Structures The staff reviewed item 7 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. Structures at VYNPS 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 in foundation 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 3-433 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 this aging effect is not applicable to VYNPS.  (8)Lock Up Due to Wear for Lubrite Radial Beam Seats in BWR Drywell and Other Sliding Support Surfaces The staff reviewed item 8 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. Owing to the wear-resistant material used, the low frequency (number of times) of movement, and the slow
 
movement 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 due to 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 of
>SRP-LR Section 3.5.2.2.2.1.
Based on the programs identified above, the sta ff concludes that the applicant's programs meet
>SRP-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).
Aging Management of Inaccessible Areas. The staff reviewed LRA Section 3.5.2.2.2.2 against the 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 SER Section 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 cracking due 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 4 for inaccessible areas.
3-434  (2)LRA Section 3.5.2.2.2.2 addresses the same accessible area discussion in SER Section 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 with aggregates 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 5 for inaccessible areas.  (3)LRA Section 3.5.2.2.2.2 addresses the same accessible area discussion in SER Section 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 stress levels 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 for inaccessible areas.  (4)LRA Section 3.5.2.2.2.2 addresses the aging management of inaccessible areas, these aging 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, these aging effects are not applicable to VYNPS.
SRP-LR Section 3.5.2.2.2.2 states that increases in porosity and permeability and loss of strength 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 3-435 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 7-9 inaccessible 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 entrainment The applicant also stated that VYNPS concrete also meets recommendations of later ACI guide ACI 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 aging management 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.
Based on the programs identified above, the applicant has met the staff concludes that the applicant'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. The staff 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 of concrete 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 to elevated temperatures may occur in PWR and BWR Groups 1-5 concrete structures. For
 
concrete elements that exceed specified te mperature 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 local areas allowed to have temperatures not to exceed 200 F. The GALL Report recommends further evaluation of a plant-specific program if any portion of the safety-related and other 3-436 concrete structures exceeds specified temper ature 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 concrete structures 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 elevated temperature 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 local area temperatures do not exceed 200F. The staff agrees with the applicant that these aging effects 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 temperatures that 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 and local area maximum temperature less than 200F. The drywell cooling system recirculates the drywell 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 elevated temperatures are not plausible aging effects due to the nonexistence of these aging
 
mechanisms. A plant-specific AMP will be ev aluated if temperature limits are exceeded.
The 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 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 Management of Inaccessible Areas for Group 6 Structures. The staff reviewed LRA Section 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 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.
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 3-437 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.
During the audit and review, the staff noted that in the discussion column of LRA Table 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 aggressive
 
environments. 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 that LRA 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 the criteria 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 cracking due to freeze-thaw may occur in below-grade inaccessible concrete areas of Group 6 3-438 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) and cracking 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-thaw 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
 
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 LRA Table 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
 
provide a copy of ACI 301 as listed in accordance with the discussion column. The
 
applicant'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 that the 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 the criteria 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 and reaction 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 with aggregates 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.
3-439 The applicant stated, in the LRA, that for cracking due to expansion and reaction 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. 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 in porosity 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
 
standards with a high cement, low water/cement ratio and the below grade environment
 
non-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 LRA Table 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 that the 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 VYNPS concrete 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) is revised 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.
3-440 During the audit and review, the staff noted that in the discussion column of LRA Table 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 stated that 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 Program will confirm the absence of aging effects requiring management for
 
VYNPS Group 6 concrete components. See
 
Section 3.5.2.2.2.4(3)."
Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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 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 Stress Corrosion Cracking and Loss of Material Due to Pitting and Crevice Corrosion. The staff reviewed LRA Section 3.5.2.2.2.5 against the criteria in SRP-LR Section 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 of material 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 pitting and 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 crevice corrosion 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 this aging effect is not applicable to VYNPS.
3-441 Based on the programs identified above, the sta ff concludes that the applicant's programs meet SRP-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 LRA Section 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 the Structures Monitoring Program.
SRP-LR Section 3.5.2.2.2.6 states that the GALL Report recommends further evaluation of certain 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
 
degradation of vibration isolation elements for Group B4 supports. Further evaluation is
 
necessary 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 certain component 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 for Groups B1 through B5 supports VYNPS concrete anchors and surrounding concrete are included in the Structures Monitoring 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 supports Loss 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 for Group B4 supports The VYNPS AMR did not identify any component support structure/aging effect combination corresponding to the GALL Report, Volume 2, Item III.B4-12.
The staff finds that the applicant has included the above aging effect/mechanism combinations within 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 3-442 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 other concrete aging mechanisms. Nonetheless, the Structures Monitoring Program will
 
confirm absence of aging effects requiring management for VYNPS concrete
 
components.
The staff was not able to find an AMR line item in Table 2 for this component (Building concrete at 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 LRA Table 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 isolation elements 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 for
 
mechanical 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 was asked to verify that there are no non-metalic (rubber) vibration isolation elements used to
 
structurally support the EDG, HVAC sy stem 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 3-443 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 sy stem 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 sta ff concludes that the applicant's programs meet SRP-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 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).
Cumulative Fatigue Damage Due to Cyclic Loading. LRA Section 3.5.2.2.2.7 states that fatigue of 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, anchor bolts, 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, anchor bolts, 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 for which 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 Report Summary of Technical Information in the Application. In LRA Tables 3.5.2-1 through 3.5.2-6, 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.
3-444 In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant indicated, via notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line
 
item in the GALL Report. The applicant provided fu rther 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, materi al, 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 in the 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 the primary containment component groups.
The staff finds that all AMR evaluation results in LRA Table 3.5.2-1 are consistent with the GALL Report, 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 additional information 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 list downcomers as a component; howev er, 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 in LRA 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 the applicant 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 Inservice Inspection Program, states that "for containment inservice inspection, including applicable relief
 
requests, general visual and detailed visual examinations are used in addition to visual testing 3-445 examinations, 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.
In its response dated October 31, 2006, the applicant stated the following:
General visual examinations are perform ed either directly or remotely with sufficient 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 to the containment surface to detect discontinuities and imperfections including such
 
conditions 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 and structural 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 im plemented 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 the applicant provided clarifications on the general visual, detailed visual, and visual testing
 
examinations, 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 Program and the Containment Inservice Inspection Pr ogram both state that, "The program includes augmented ultrasonic exams to measure wall thick ness 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 ASMECode Section XI, "Inservice Inspection Program."
In its response dated October 31, 2006, the applicant stated:
3-446ASME Code, Section XI, IWE-1240 "Surface Areas Requiring Augmented Examination" establishes criteria for determining the need for augmented
 
examinations. This sentence was included in the description of the Inservice
 
Inspection-Containment Inservice Inspection Program in LRA Sections A.2.1.16
 
and 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 VYN PS Containment Inservice InspectionProgram 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 the applicant 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 that the 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 dated October 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 3401 3-447pH6.26.6chloride (ppm)322145 The applicant stated that the sulfate values are not available because the station's indirect discharge 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 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 evaluated for sulfate, pH and chloride levels.
Finally, in its response, the applicant stated that the Vermont Agency of Natural Resources has attributed 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 the measured 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 the aggregates 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 the concrete 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 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).
3.5.2.3.2  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 the reactor building component groups.
3-448 In LRA Table 3.5.2-2, the applicant proposed to manage loss of material of stainless materials for component types of spent fuel pool storage racks exposed to a fluid environment using the "Water Chemistry Control-BWR."
During the audit and review, the staff noted that in LRA Table 3.5.2-2, for component spent fuel pool 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 spent fuel pool treated water environment is less than 140F.The staff reviewed the applicant's Water Chemistry Control-BWR Program and its evaluation is documented 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 racks
 
exposed to a fluid environment is properly managed by the Water Chemistry Control-BWR Program, which through the addition of chemical s 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 steel material 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 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).
3.5.2.3.3  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 the intake structure component groups.
The staff finds all AMR evaluation results in LRA Table 3.5.2-3 are consistent with the GALL Report, 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 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).
3-449 3.5.2.3.4  Process Facilities Summary of Aging Management Evaluation-LRA Table 3.5.2-4 The staff reviewed LRA Table 3.5.2-4, which summarizes the results of AMR evaluations for the process facilities component groups.
In LRA Table 3.5.2-4, the applicant proposed to manage loss of material, cracking and change in 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 is documented 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 n N o. 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 and change 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 in material 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 is documented 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 envir onment are properly managed by the Structures Monitoring Program, which through an enhancement to program element Detection of Aging
 
Effects will provide guidance for performing structur al 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.
3-450 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).
3.5.2.3.5  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 the yard structures component groups.
The staff finds all AMR evaluation results in LRA Table 3.5.2-5 are consistent with the GALL Report, 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 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).
3.5.2.3.6  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 the bulk commodities component groups.
In LRA Table 3.5.2-6, the applicant proposed to manage cracking and delamination separation of 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 SER Section 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 protected
 
from weather environment is properly managed by the Fire Protection Program, which in accordance with program element Detection of Ag ing 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 envir onment 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.
In addition, in LRA Table 3.5.2-6, the applicant proposed to manage loss of material of cerafiber and cera blanket materials for component types of fire wrap exposed to a protected from weather
 
environment using "Fire Protection."
3-451 The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in SER 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 Fi re Protection Program, which in accordance with program element Detection of Aging Effect s 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 material properties 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] ex posed to a protected from weather environment using "Periodic Surveillance and Preventive Maintenance."
The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program and 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 maintenanc e 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 envir onment 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 of seals 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.
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).
3-452 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 management evaluations 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 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 3.5.1-20, 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 prestressed containment: 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 form of 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.
On 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 of Group 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 3-453 significant preload (in the order of 70percent 70 percent 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 for Group 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 of Groups 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 to be managed for the period of extended operation.
* If proper design prevents distortion, overload, and fatigue due to vibratory and cyclic thermal 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 of these conditions.
* Explain where sliding support bearing and sliding support surfaces are used in component groups B2 and B4 at VYNPS and pr ovide the environment they are exposed to.During interviews with the applicant's technical personnel, the applicant stated that loss of material 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.
The applicant also stated that the sliding surface material used at VYNPS is lubrite, which is a corrosion 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.
3-454 In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.1, Item 3.5.1-52 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 to vibratory, 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 than corrosion, 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 of Groups 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 which needs to be managed for the period of extended operation.
* If proper design prevents distortion, overload, and fatigue due to vibratory and cyclic thermal 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 of these conditions.
* Explain what VYNPS inspects for during VT
-3 visual examinations of groups B1.1, B1.2 and 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 the discussion 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 3-455 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 LRA Table 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 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. 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 to vibratory, 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 than corrosion, 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 isolation function 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.
The staff finds that VYNPS does not have Group B1.1, B1.2, and B1.3 vibration isolation elements 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 the structures 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 aging effects 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 fr om 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:
3-456
* high cement content
* low water-to-cement ratio
* proper curing
* adequate air entrainment The applicant also stated that VYNPS concrete also meets guidelines of later guide ACI 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 3 percent and 5percent 5 percent 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
 
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 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 and standards 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.
 
Therefore, no aging effects are considered to be applicable to components fabricated from
 
concrete material protected from weather, ex posed 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 finds that 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 weat her, 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 w eather 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), for component 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.
3-457 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 since quality 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 with associated 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 effects were 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 aging effects 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 high
 
intensities 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 to
 
vibratory and cyclic thermal loads are not considered to be aging effects requiring management
 
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 expos ed to a protected from weather environment.
On the basis of its review of current industry research and operating experience, the staff finds that a protected from weather environment on lubr ite 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 protect ed 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 aging effects 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.
3-458 In the LRA the applicant states that the ambient environment at VYNPS is not chemically polluted by vapors of SO 2 or other similar substances and the external environment does not contain 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 mate rial 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 alum inum 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 env ironment 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 com ponents 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 aging effects 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 chemically polluted by vapors of SO 2 or other similar substances and the external environment does not contain 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
 
stainless steel components. Therefore, loss of material due to pitting and crevice corrosion is not
 
an 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 aging effects 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), for component steel piles, material carbon steel ex posed to weather environment; the aging effect is 3-459 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 as identified 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. Al though 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 no significant 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 a weather environment (non-aggressive soil environment) on ca rbon 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 carbon steel in a weat her environment (non-aggressive soil 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 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 aging effects 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), for component 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 that Pyrocrete (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.
3-460 The staff finds pyrocrete to be a cementitious material that like concrete in a protected from weather environment will not experience aging e ffects. 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 a protected 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 fr om 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 pyrocr ete 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 aging effects 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
 
weather do not experience aging effects that would significantly degrade their ability to insulate
 
as 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 finds that 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 expos ed 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 aging effects 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), for component 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 c ould 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.
3-461 During interviews with the applicant's technical personnel, the applicant's staff stated that the PVC 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 water
 
stop 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 them from a fluid environment and expose them only to a protected from weather environment, the staff finds that a protected from weather envir onment 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.
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).
 
====3.5.3 Conclusion====
The staff concludes that the applicant has provided sufficient information 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).
 
===3.6 Aging===
Management of Electrical and Instrumentation and Controls System This section of the SER documents the staff's review of the applicant's AMR results for the electrical 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 Application LRA Section 3.6 provides AMR results for the electrical and I&C system components and component 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 elec trical and I&C system components and component groups.
3-462 The applicant's AMRs evaluated and incorporated applicable plant-specific and industry operating 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====
Evaluation The staff reviewed LRA Section 3.6 to determine whether the applicant provided sufficient information 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 AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters
 
described in the GALL Report; however, the staff did verify that the material presented in the
 
LRA was applicable and that the applicant 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 3.6.2.1.
In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations
 
were consistent with the 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, and AMPs 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 Report 3-463Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation Electrical equipment subject to 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements
 
(3.6.1-1)Degradation due to various aging
 
mechanisms Environmental Qualification of
 
Electric ComponentsTLAA Environmental Qualification 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 mechanisms Electrical Cables and Connections
 
Not Subject to 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements Non-Environmental Qualification
 
Insulated Cables
 
and Connections
 
Program (B.1.19)Consistent with GALL Report. (See
 
SER Section 3.6.2.1)
Conductor 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 mechanisms Electrical Cables And Connections
 
Used In Instrumentation
 
Circuits Not Subject To 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements Non-Environmental Qualification
 
Instrumentation Circuits Test Review
 
Program (B.1.18)Consistent with GALL 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 Inaccessible Medium Voltage
 
Cables Not Subject to 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements Non-Environmental Qualification
 
Inaccessible
 
Medium-Voltage
 
Cable Program (B.1.17)Consistent with GALL 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 Acid CorrosionNoneNot applicable to BWRs Component Group(GALL Report Item No.)Aging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-464 Fuse 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-Enclosed Bus -
Bus/connections
 
(3.6.1-7)Loosening of bolted connections due to thermal cycling and
 
ohmic heatingMetal-Enclosed BusMetal-Enclosed Bus Program AMR results that arenot consistent with
 
the GALL Report or
 
not addressed in the
 
GALL Report. (See
 
SER Section 3.6.2.3)
Metal-Enclosed Bus -
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 Program AMR results that arenot consistent with
 
the GALL Report or
 
not addressed in the
 
GALL Report. (See
 
SER Section 3.6.2.3)
Metal-Enclosed Bus - Enclosure
 
assemblies
 
(3.6.1-9)Loss of material due to general corrosion Structures Monitoring Program Metal-Enclosed Bus Program AMR results that arenot consistent with
 
the GALL Report or
 
not addressed in the
 
GALL Report. (See
 
SER Section 3.6.2.3)
Metal-Enclosed Bus - Enclosure
 
assemblies
 
(3.6.1-10)
Hardening and loss of strength due to
 
elastomers
 
degradation Structures Monitoring Program Metal-Enclosed Bus Program AMR 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 GALLReportAMP in LRAStaff Evaluation 3-465 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-specific AMP is to be
 
evaluatedNoneConsistent with theGALL Report, which
 
recommends further
 
evaluation.
(See SER Section 3.6.2.2.2)Transmission 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-specific AMP 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
 
oxidation Electrical Cable Connections 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 of several 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 Report 3-466 Summary of Technical Information in the Application. LRA Section 3.6.2.1 identifies the materials, 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 LRA Table 3.6.2-1 summarizes AMRs for the electrical and I&C system components and indicates AMRs claimed to be consistent with the GALL Report.
Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant claimed 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 the information 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 consistent with 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 consistent with 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.
3-467 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 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 evaluation follows.
The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience
 
and proposals for managing 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 Recommended Summary of Information in the Application. In LRA Section 3.6.2.2, the applicant further evaluates aging management, as recommended by t he GALL Report, for the electrical and I&C system components and provides information c oncerning 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 of material due to mechanical wear
* 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
* quality assurance for aging management of nonsafety-related components Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant claimed 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, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 3-468 10 CFR 54.21(c)(1). SER Section 4.4 documents the staff's review of the applicant's evaluation of this TLAA.
3.6.2.2.2  Degradation of Insulator Quality Due to Salt Deposits or Surface Contamination, Loss of Material Due to Mechanical Wear The 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 to presence 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 or surface 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 are those used to support uninsulated, high-voltage electrical components such as transmission
 
conductors and switchyard buses.
The applicant further stated, in the LRA, that various airborne materials such as dust, salt and industrial 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 greater concentration 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 and suspension insulators in that they are subject to movement. Although this mechanism is
 
possible, industry experience has shown that transmission conductors do not normally swing and
 
that when they do, due to a substantial wind, they do not continue to swing for very long once the 3-469 wind has subsided. Wear has not been apparent during routine inspections. The staff finds the applicant's assessment acceptable.
The staff concludes that there are no aging effects requiring management for VYNPS high-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 sta ff concludes that the applicant's programs meet SRP-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 Conductor Strength Due to Corrosion, and Increased Resistance of Connection Due to Oxidation or Loss of
 
Pre-Load The 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 induced abrasion 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, stranded electrical cables used outside buildings in high-voltage applications. The transmission conductor
 
commodity group includes the associated fastening hardware, but excludes the high-voltage
 
insulators. 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 aging effects 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 meteorological conditions.
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 ACSR conductor is a
 
very slow acting mechanism, and the corrosion rates depend on air quality, which includes 3-470 suspended particles chemistry, SO 2 concentration in air, precipitation, fog chemistry and meteorological conditions. Air quality in rural areas generally contains low concentration of
 
suspended particles and SO 2 , which keeps the corrosion rate to a minimum. Tests performed by Ontario 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 strain and 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 l oading. 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 are necessary 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 connecti ons 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 aluminum switchyard 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 may be 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 3-471 connections. An electrical connection must be designed to remain tight with 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., 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 the
 
applicant 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 switchyard bus is not applicable since all switchyard bus connections requiring an AMR are welded
 
connections. 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 measur e any hot spot temperature within normally enclosed transformer termination enclosures.
The staff finds the applicant's response acceptable because for transmission conductor and switchyard 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 of conductor 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 maintenanc e 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 meet SRP-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).
3-472 3.6.2.2.4  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 for which 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 Report Summary of Technical Information in the Application. In LRA Table 3.6.2-1, 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.
In LRA Table 3.6.2-1, the applicant indicated, via notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the
 
GALL Report. The applicant provided further in formation 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, materi al, 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 in the 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-LRA Table 3.6.2-1 The staff reviewed LRA Table 3.6.2-1, which summarizes the results of AMR evaluations for the electrical and I&C components and component groups.
In LRA, Table 3.6.2-1, the applicant stated that no aging effects requiring management and no AMP 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 3-473 associated with cables within the scope of license renewal are part of this program, regardless of their association with active or passive components.
The staff requested that the applicant provide a basis document including an AMP with the program 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 stressors
 
for the metallic parts of electrical cable connections identified no aging effects requiring
 
management. Metallic parts of electrical cable c onnections potentially exposed to thermal cycling and ohmic heating are those carrying significant cu rrent 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 stress
 
associated with electrical faults is not a credible aging mechanism because of the low frequency
 
of 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's determination. 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, vi brations, chemical contamination, corrosion, and oxidation 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 terminations 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 mange the aging
 
effects of cable connections. Several licensee event reports indicated loose connections due to
 
corrosion, vibration, thermal cycling, etc. Al so, past applicants have used thermography to detect 3-474 weak/loose connections and corrected them as soon as possible, and provided anAMP 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 an AMP 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 the maintenance 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 c able 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 revi ew 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 periodi c 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 cable connections 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.
The staff reviewed the applicant's response and in a followup to RAI 3.6.2.2-N-01 stated that the current 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 ex isting 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 3-475 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, of components 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 fo r electrical cable connections (metallic parts).
Therefore, the staff requested, in RAI 3.6.2.2-N-01, that the applicant either provide a plant-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 ex isting programs will address the above aging effects and provide detailed discussion of how its curr ent program meets the program elements as described in the SRP-LR.
The staff also requested that the applicant provide supporting documentation to show that the AMP 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.
In a letter dated January 4, 2007, License Renewal Application, Amendment 23, the applicant provided 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 by evaluating 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.
3-476 Connections for all voltage levels are considered. Bolted connections are the main 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 potential stressors 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 its Bolted 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 is acceptable. 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 existing
 
maintenance 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.
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).
3.6.2.3.2  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 management evaluations 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 3-477 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 containmentassemblies.
For uninsulated ground conductors, the applicant stated in plant basis document that uninsulated 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 structural features 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 ground conductors and no mention was made of a safety-related function or intended function for license
 
renewal. VYNPS uninsulated ground conductors including grounding rods, buried ground cables, 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 of a larger assembly) metallic clamp due to ohmic heating, thermal cycling, electrical transients, frequent manipulation, vibration, chemical contamination, corrosion, and oxidation is not
 
applicable 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 cables and
 
connections indicated that the only fuse holders installed at VYNPS that utilize metallic 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 that perform 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 GALL Report 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 3-478 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 renewal function. 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 safety analyses 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 immediate access and one delayed access. The delay access circuits is available by opening the generator no-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 offsite power 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 trans formers. 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. The applicant
 
committed to develop the MEB program. The VYNPS Metal-Enclosed Bus Program will be added
 
to the following LRA sections:
Section 2.5 - Electrical and I&C Systems Section 3.6 - Electrical and Instrumentation and Controls
 
Table 3.6.1
 
Table 3.6.2-1
 
Appendix A
 
Appendix B In a letter dated October 17, 2006, the applicant revised its LRA. The applicant added LRA Sections A.2.1.38 and B.1.32 describing its Metal Enclosed Bus Inspection Program. The
 
applicant also included the program basis docum ent 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.
3-479 All SSCs relied on in safety analyses or plant ev aluation to perform a function that demonstrates compliance 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, two 13.8 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
 
either of the two VYNPS 4160 V emergency buses and is capable of supplying
 
power 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 3-480 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 source
 
together 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 that can 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
 
includes the switchyard circuit breakers near the Vernon Dam that feed the Vernon tie
 
transformer, 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 3-481 Non-EQ Inaccessible Medium-Voltage Cable Program addressed the underground cables from Vernon 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 applicant stated: The Statement of Considerations required by 10 CFR Part 54 clearly states that crediting regulatory required redundancy as a surrogate for an aging management program is inappropriate."Further, the Commission believes that crediting a regulatory requirement (i.e., redundancy)
[emphasis added] as a surrogate for an aging management program to 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-lived electrical components from an AMR based solely on required redundancy. However, the multiple generators 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 design incorporates redundancy that is not required by regulations.
The applicant also stated that unlike many typical SBO AAC sources, the VHS and portions of the 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
 
continuously operate provides verification that they remain capable of performing their license
 
renewal 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 VHS generators to the Vernon Tie breaker and that operating experience confirms this conclusion.
 
Historically, VHS reliability has exceeded the reliability specified in guidance documents for
 
meeting the SBO rule, specifically, the 95 percent availability specified in NUMARC 87-00. In
 
fact, historical availability far exceeds that ex pected 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 t he medium-voltage underground cable from the VHS powerhouse 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 continued reliable switchyard performance.
3-482 The applicant also stated in a report that VHS with multiple units, has demonstrated reliability far in excess of an auxiliary generator (99.9 perc ent 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 that redundancy 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
 
failures and may prevent them from performing their intended functions. On this basis, the staff
 
concludes 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 break er 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 applicant provided 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 ensure continued 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 connections preclude 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.
3-483 Thermal infrared inspection was performed at the VHS substation on 10/06/06 and there were no abnormalities found.
Loss of material due to corrosion of connections or surface oxidation is an applicable 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 clarification is acceptable because the design of transmission connections 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 inaccessible medium-voltage (2 kV to 35 kV) cables asso ciated 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 ar e 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 applicant stated: Inaccessible medium-voltage cables asso ciated with SBO AAC source from the VHS 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 t he Non-Environmental Qualification Medium-Voltage Cable Program described in LRA Appendix B. The 3-484 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 function of 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 disagrees with
 
the applicant's argument that redundancy and normal operation of VHS preclude an 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 for RAI 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 satisfy the 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 underground medium-voltage cables do not have agi ng effects that require management.
Reduced insulation resistance due to moisture and voltage stress is an aging effect 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 VHS switchyard is similar to the VYNPS startup transformer to 4160 V switchgear
 
cable.
3-485  aBoth have ethylene-propylene rubber (EPR) insulation at a 133 %
insulation level. bThe VHS cable has specified a chloro-sulfonated polyethylene jacket. Per NEI 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 physical configuration (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 each other, so they experience identical environmental conditions. Even though the VHS switchyard is closer to the river and lower in elevation than
 
VYNPS and because the VHS switchyard is located downstream of the
 
VHS, the water table is at a similar level to VYNPS. eBoth cables utilize red or pink EPR insulation, as black EPR production ended 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 industry indicated 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 of startup 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 VHS cable providing a leading indicator for the VHS cable. bThe startup transformer cable is loaded intermittently, and the VHS cable is continuously loaded. As such, the VHS cable insulation heating is more 3-486 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 White Paper,"
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 will document 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.The 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 not represent 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 repr esent 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 dirt
 
may 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 of
 
extended 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 switchyard remains open.In response to the staff's concerning about not testing inaccessible medium cables at VHS, the applicant, 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.
3-487 The staff found the applicant's response acceptable because testing of inaccessible medium voltage 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 are effectively 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.
In 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 their intended 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 for electrical 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 for RAI 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 is acceptable. 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 it related to SBO AAC:
3-488  (a)Please describe (as stated in GALL XI.E6) how aging effects are managed so that the intended 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 should be 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 bus within the VHS switchyards (69 kV and 13.8 kV) is not a concern.
 
  (d)Per LRA 3.6, increased resistance of connections due to oxidation is not an applicable aging 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 surface more 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 with the 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 cycling and 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 stress
 
associated with electrical faults is not a credible aging mechanism because of the
 
low 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 chemicals
 
to areas inside VHS or the associated switchyard do not occur. Corrosive
 
chemicals are not a normal environment fo r electrical connections. Contamination 3-489 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
 
mechanisms for the SBO AAC source. In addition, normal operation of the VHS
 
circuit 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's response 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, vi brations, chemical contamination, corrosion, and oxidation 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 loose
 
terminations 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 for RAI 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 el ectrical 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 applicant
 
did 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."
3-490 By letter dated January 4, 2007 the applicant 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."
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.
In response to the staff's request in RAI 3.6.2.2-N-08(b), in a letter dated October 20, 2006, the applicant 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, the applicant stated that:
The VHS switchyard employs an aerial cable system (transmission conductors suspended 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 cable connections 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 mate rials 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 3-491 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.
In a letter dated January 4, 2007, the applicant provided additional clarification for RAI 3.6.2.2-N-08-5(c). Specifically, the applicant stated:
The design of the transmission conductor and switchyard bus bolted connections preclude 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 10/06/06 with no abnormalities found.
The staff finds that the applicant's response is acceptable because the design of transmission connections 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, rigid electrical 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 to preclude an AMR. Corrosion of cable connections at VHS switchyard is a concern. This
 
corrosion 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.
3-492 In a letter dated January 4, 2007, License Renewal Application, Amendment 23, the applicant provided 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 an applicable 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 compound prevents 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 can contaminate insulator surfaces. The surface contamination is typically washed
 
away by rain. Surface contamination c an 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
 
cement growth are not applicable degradation mechanisms for high-voltage
 
insulators 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 3-493 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 as well 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 and surface 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 evaluated the 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 Conclusion====
The staff concludes that the applicant has provided sufficient information 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).
3-4943.7  Conclusion for Aging Management Review Results The staff reviewed the information in LRA Section 3, "Aging Management Review Results," and LRA 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 the applicant will continue to conduct the activities authorized by the renewed license will continue to
 
be 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 4 TIME-LIMITED AGING ANALYSES4.1  Identification of Time-Limited Aging Analyses This section of the safety evaluation report (SER) addresses the identification of time-limited aging 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 by the current operating term. In accordance with Title 10, Section 54.21(c)(1), of the Code of Federal Regulations (10 CFR 54.21(c)(1)), applicants must list TLAAs as defined in 10 CFR 54.3.
In addition, as required by 10 CFR 54.21(c)(2), applicants list plant-specific exemptions granted in 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 Application To identify the TLAAs, the applicant evaluated calculations for VYNPS against the six criteria specified 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 4-2 In compliance with 10 CFR 54.21(c)(2), the applicant stated that it had not identified exemptions granted in accordance with 10 CFR 50.12, based on a TLAA, as required by 10 CFR 54.3.
 
====4.1.2 Staff====
Evaluation LRA Section 4.1 lists the VYNPS TLAAs. The staff reviewed the information to determine whether 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, as required by 10 CFR 54.4(a)  (2)consider the effects of aging (3)involve time-limited assumptions def ined 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 the system, 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 CLB The applicant listed common TLAAs from US NRC NUREG-1800, Revision 1, "Standard Review Plan 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 accordance with 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 Conclusion====
On the basis of its review, the staff concludes that the applicant provided an acceptable list of TLAAs, 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.
4-3 4.2  Reactor Vessel Neutron Embrittlement Analyses Reactor vessel integrity is governed by the requirements of 10 CFR Part 50, "Domestic Licensing 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 the beltline 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 V USE) reduction due to 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), the mean value of the adjustment in reference temperature caused by irradiation (delta RT NDT), and a 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 or a 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 are considered 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 relief and the axial weld failure probability.
Appendix G of 10 CFR Part 50, provides the requirements for maintaining acceptable levels of upper-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 Pressure Vessel ASME Code, Section XI, Appendix G. 10 CFR 50, Appendix G, also requires 4-4 that 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 values
>and describes two methods for determining USE values for RV beltline materials, depending on
 
whether 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 (1/4 T) of the RV wall, the neutron fluence used in the USE analysis is the neutron fluence at the 1/4 T depth location.
The applicant has described its evaluation of these TLAAs in LRA Section 4.2, "Neutron Embrittlement of the Reactor Vessel and Internals," and LRA Section 4.7, "Other Plant-Specific
 
TLAA." In order to demonstrate that neutron embr ittlement 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 plate
 
====4.2.1 Reactor====
Vessel Fluence 4.2.1.1  Summary of Technical Information in the Application LRA Section 4.2.1 summarizes the evaluation of RV fluence for the period of extended operation.
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 17 n/cm 2 (E greater than 1 MeV). Using RG 1.99, Revision 2, Equation (3) results in a 54 EFPY 1/4 T fluence of 3.98 x
>10 17 n/cm 2 (E greater than 1 MeV). The 40-year beltline consists of four plates (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 axial distribution of fast
 
fluence at the reactor pressure vessel (RPV) wall. With the additional fluence during the period of 4-5 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 10 inches 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 Evaluation The staff reviewed LRA Section 4.2.1 to verify, as required by 10 CFR 54.21(c)(1)(ii), that the analyses 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 LRA Section 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 life calculated 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 axial fluence 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 in GE-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.1/4 T fluence, n/cm 2 (E>1 Mev)
Location Original Extrapolation from 32 EFPY curve Revised Extrapolation from 32 curve Extrapolation from 60-year curve BAF9.8E+169.8E+161.0E+17 BAF + 19%1.2E+171.2E+171.2E+17 nozzle6.7E+166.4E+167.5E+16 nozzle + 19%7.9E+167.6E+169.0E+16 4-6 As indicated in this table, the projected fluence at the nozzle is still less than 1x10 17 n/cm 2 (E>1 Mev). Even when 19 percent is added to the extrapolated value 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 value was 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 peak fluence value of 5.16 x 10 17 n/cm 2 is at an elevation of 75 inches above the bottom active fuel level. 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 Supplement The applicant provided a UFSAR Supplement summary description of its TLAA evaluation of RV fluence in LRA Section A.2.2.1.1 which include the following:
Calculated fluence is based on a time-limited assumption defined by the operating term. As such, fluence is the time-limited assumption for the TLAA that evaluates
 
RV embrittlement.
GE's Licensing Topical Report NEDC-32983P-A, which was approved by the NRC 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 fluence appropriately 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 summary description of the applicant's actions to address RV fluence is adequate.
4.2.1.4  Conclusion On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated, in compliance with 10 CFR 54.21(c)(1)(ii), that, for RV fluence, the analyses have 4-7 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 Application LRA 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 3/4 T ART to determine the P-T limits. LRA Table 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 T ARTof 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, the TLAA for P-T limits remains valid for the period of extended operation.
4.2.2.2  Staff Evaluation The staff reviewed LRA Section 4.2.2 to verify in accordance with 10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of extended operation.
In its March 2003 license amendment request, VYNPS requested use of the present P-T limit curves 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 the applicant'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 were originally prepared based on a 1/4 T fluence of 1.24 x 10 18 n/cm 2 (E greater than 1 MeV) from the 1984 fluence analysis. This fluence value was determined to be overly conservative based a
 
subsequent 32 EFPY fluence calculation that generated a 1/4 T 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 4-8 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 limit curve 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
 
of extended operation. The staff reviewed the applicant's response and finds the response
 
acceptable 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 be submitted 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 per iod 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 amendment requesting 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 changes to 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 Supplement The applicant provided a UFSAR Supplement summary description of its TLAA evaluation of P-T limits in LRA Section A.2.2.1.2. which include the following:
4-9 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-T limits 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 summary description of the applicant's actions to address P-T limits is adequate.
4.2.2.4  Conclusion The 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 10 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 has demonstrated, 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 Application LRA Section 4.2.3 summarizes the evaluation of C V USE 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 the life
 
of the vessel of no less than 50 ft-lb."
RG 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials," provides two methods or positions for estimating C V USE at end of life. Position 1 applies to material without 4-10 surveillance 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 V USE for a stated copper content and neutron fluence is determined by reference to RG 1.99, Revision 2, Figure 2.
This percentage drop is applied to the initial C V USE to obtain the adjusted C V USE. LRA Table 4.2-2 calculates the end of life C V USE by this method. Safety Analysis Report NEDC-33090P documents the most recent calculations of C V USE. Analyses were done for 51.6 EFPY. Results of NEDC-33090P were extrapolated to 54 EFPY. The unirradiated
 
surveillance specimens were from plate 1-14 with a C V USE of 89 ft-lb (137 ft-lb times 0.65). The 54 EFPY C V USE 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 V USE with the fluence determined in SER Section 4.2.1. For 54 EFPY, LRA Table 4.2-2 shows the minimum projected C V USE for plate 1-14 remaining above the 50 ft-lb requirement of 10 CFR Part 50, Appendix G.
Initial (un-irradiated) USE data for the weld materials and for plates 1-15, 1-16, and 1-17 do not exist. 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 Evaluation The staff reviewed LRA Section 4.2.3 to verify 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.
Section IV.A.1.a of 10 CFR Part 50, Appendix G to, requires in part that RV beltline materials have C V USE values in the transverse direction for base metal and along the weld for weld material of no less than 50 ft-lb, unless it is demonstrated in a manner approved by the staff, that
 
lower values of C V USE will ensure margins of safety against fracture equivalent to those requiredby ASME Code, Section XI, Appendix G.
In accordance with RG 1.99, Revision 2, the predicted decrease in USE due to neutron embrittlement during plant operation is dependent upon the amount of copper in the material and 4-11 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 at VYNPS. 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.
The applicant was able to directly calculate the predicted EOL USE value for RV beltline plate 1-14 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 demonstrate that 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 2
>Predicted 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 irradiation using 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 Supplement 4-12 The applicant provided a UFSAR Supplement summary description of its TLAA evaluation of C V USE 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 data and unirradiated USE data submitted to the NRC in support of the VYNPS power
 
uprate, and the 1/4 T 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.Because VYNPS does not have complete unirradiated data for all beltline materials, 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 1/4 T fluence value is assumed for all plates and welds.
The applicant's UFSAR Supplement summary description is consistent with the staff analysis for the 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 summary description of the applicant's actions to address C V USE is adequate.
4.2.3.4  Conclusion On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(ii), that, for C V USE, 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).
 
====4.2.4 Adjusted====
Reference Temperature 4.2.4.1  Summary of Technical Information in the Application LRA 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 reference temperature 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 reference temperature, RT NDT , is the difference in the 30 ft-lb index temperatures from the average Charpy 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; interpolated 4-13 chemistry factors (CFs) from RG 1.99, Table 1; initial RT NDT values and standard deviations from NEDC-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 T fluence.
Fluence factors (FFs) were calculated using RG 1.99, Revision 2, Equation 2.
>The applicant calculated extrapolated RT NDT values by multiplying the CF and the FF for each plate and weld, then added the initial RT NDT , the calculated RT NDT , and the calculated margins for 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 thus projected through the period of extended operation.
4.2.4.2  Staff Evaluation The staff reviewed LRA Section 4.2.4 to verify 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.
The applicant calculated the 54 EFPY fluences for the VYNPS RV beltline materials using the fluence 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 for the 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 NDT values 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 NDT values 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 NDT values listed in LRA Table 4.2-4 were originally provided to the NRC with the proposed TS amendment
 
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 NDT values 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 pr oposed 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 response resolves the issue in RAI 4.2.4-1.
The staff independently reviewed all ART calculations in LRA Table 4.2-4 based on the approved 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 4-14 beltline materials.
4.2.4.3  UFSAR Supplement The applicant provided a UFSAR Supplement summary description of its TLAA evaluation of adjusted 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 of
>RG  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 support of the VYNPS power uprate, and the 1/4 T fluence maximum value. New fluence factors (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, for calculating 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 summary description of the applicant's actions to address adjusted reference temperature is adequate.
4.2.4.4  Conclusion The staff reviewed the applicant's TLAA of the ART calculations, as summarized in SER Section 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 has demonstrated, 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 Application LRA Section 4.2.5 summarizes the evaluation of RV circumferential welds inspection relief for the period of extended operation. BWRVIP-74 reiterated the recommendation of BWRVIP-05 to
 
exempt RPV circumferential welds from ex amination. 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 4-15 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
 
RV circumferential weld inspection relief request. The evaluations have been projected to 54
 
EFPY. 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 probabilistic fracture 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 a result, the shift in reference temperature, delta RT NDT , is lower for VYNPS at 54 EFPY compared to the NRC analysis. This lower delta RT NDT value yields a mean RT NDT value that is considerably lower 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 EFPY mean RT NDT provided by the NRC.
Based on this analysis, the applicant concluded that the VYNPS RV circumferential weld conditional 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 Evaluation The staff reviewed LRA Section 4.2.5 to verify, 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.The technical basis for relief from the ASME Code, Section XI, "Circumferential Weld Inservice Inspection (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 ci rcumferential RV welds by demonstrating that:
4-16 (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
 
applicant implemented operator training and established procedures that limit the frequency of
 
cold 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 report conservatively 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 64 EFPY 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 applicant submitted 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 of extended 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 SER Section 4.2.4. The 54 EFPY mean RT NDT value for the limiting beltline circumferential weld at VYNPS is 32.9 F. The staff checked the applicant's calculations using the data presented in LRA Table 4.2-5 and found them accurate. This 54 EFPY mean RT NDT value for the limiting VYNPS circumferential weld is bounded by the 64 EFPY mean RT NDT value of 70.6 F used by the 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 dated July 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) from BWRVIP-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.
4-17 In its response to RAI 4.2.5-1, the applicant provided a description of reactor operator training and 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 request for 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 because>the applicant will submit a request for relief from ASME Code, Section XI, requirements pursuant to 10 CFR 50.55a(g). 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 RV circumferential 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 axial shell 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 because it has been determined that no relevant indications of cracking or other age-
>related degradation mechanisms in the welds have been identified. 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 54 EFPY 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).
4-18 4.2.5.3  UFSAR Supplement The applicant provided a UFSAR Supplement summary description of its TLAA evaluation of RV circumferential welds inspection relief in LRA Section A.2.2.1.5., which includes:
Relief from RV circumferential weld exam ination requirements of GL 98-05 is based on assessments 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 original 40-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 the corresponding 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 circumferential weld 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 summary description of the applicant's actions to address RV circumferential welds inspection relief is
 
adequate.4.2.5.4  Conclusion The staff reviewed the applicant's TLAA of the RV circumferential weld examination relief, as summarized 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 has demonstrated, 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).
4-19 4.2.6  Reactor Vessel Axial Weld Failure Probability 4.2.6.1  Summary of Technical Information in the Application LRA Section 4.2.6 summarizes the evaluation of RV axial weld failure probability for the period of extended 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 documented in 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 for BWRVIP-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 is dependent 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 limiting axial 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 NDT value 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. The VYNPS limiting axial weld mean RT NDT value also falls well within the 64 EFPY value reported in BWRVIP-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 Evaluation The staff reviewed LRA Section 4.2.6 to verify 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.
In its July 28, 1998 letter to Mr. C. Terry, the BWRVIP Chairman, the staff identified a concern regarding 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 frequency of 2.73 x 10
-6 per reactor-year of operation. The applicant calculated, and the staff confirmed, that the limiting axial weld mean RT NDT value for VYNPS at 54 EFPY is 16.5F ,. This RT NDT value>supports 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.
4-20 The limiting axial weld failure probability calculated by the NRC staff in the BWRVIP-05 SER supplement 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 ASMECode, 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 examinati on 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 within the 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 co verage 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 at 54 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 the axial weld coverage achieved for the fourth ISI interval at VYNPS and the 90 percent minimum
 
coverage required to meet the "essentially 100 per cent" 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 for Clinton resulted in an NRC-calculated axial weld failure probability of only 2.73 x 10
-6 per reactor year, it can be concluded that even with the limit ed-scope coverage of the axial welds, the axial weld failure probability would not exceed 5 x 10
-6 per reactor operating year during the extended license term.
The third ISI interval at VYNPS ended during the fall of 2003. Relief for the limited-scope axial weld 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 examinati on coverage at least 12 months prior to the end of the fourth ISI interval.
4-21 The anticipated changes in metallurgical conditions expected over the period of extended operation 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 Supplement The applicant provided a UFSAR Supplement summary description of its TLAA evaluation of RV axial 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 on generic 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-05 showed 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 the limiting 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 dependent upon 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 the limiting 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 the BWRVIP-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 the RV 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 summary description of the applicant's actions to address RV axial weld failure probability is adequate.
4-22 4.2.6.4  Conclusion The staff reviewed the applicant's TLAA of the RV axial weld failure probability, as summarized in LRA 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 has demonstrated, 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 Analyses Fatigue 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 stre sses 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 mechanical components are described and evaluated below. Cumulative usage factors (CUFs) have been
 
documented and the actual numbers of design trans ient cycles have been projected to 60 years.
The CUF sums the fatigue damage from each transient. The ASME Code Section III criterion
 
requires 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, a program is in place to track cycles and to pr ovide corrective actions if limits are approached. In addition to metal fatigue analyses, fracture mechanics analyses of flaw indications discovered
 
during 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 Fatigue Class 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 they
 
are based on a number of transient cycles assumed for a 40-year plant life, these evaluations are considered TLAAs. Design cyclic loadings and thermal conditions for the Class 1 components are 4-23 defined 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 Vessel 4.3.1.1.1  Summary of Technical Information in the Application LRA Section 4.3.1.1 summarizes the evaluation of RPV fatigue analyses for the period of extended 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 closely
 
and to make them easier to track while still bounding the original design transients. The Fatigue
 
Monitoring Program will assure that the allow ed number of transient cycles is not exceeded by requiring corrective action if transient cy cle 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), that the 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 ASME Code 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 of assumed transients would not be exceeded during the period of extended
 
operation.(ii)The existing CUF calculations have been reevaluated based on an increased 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 for monitoring 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
 
compliance with 10 CFR 54.21(c)(1)(iii). The GALL Report may be 4-24 referenced 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 are found 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 Fatigue Monitoring 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 the applicant'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 higher the rate the higher the stress.
In RAI 4.3-H-03, dated August 1, 2006, the staff requested that the applicant provide documentation 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 dated January 4, 2007, stating that the vessel has been analyzed for 200 heatup/cooldown cycle}}

Latest revision as of 17:44, 14 January 2025

Compare Vermont Yankee SER with Hole (Dec 2007) to Vermont Yankee FSER (Feb 2008)
ML080720639
Person / Time
Site: Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date: 02/29/2008
From: Rowley J
NRC/NRR/ADRO/DLR
To:
Entergy Nuclear Operations
Rowley J, NRR/DLR/RLRB, 415-4053
References
Download: ML080720639 (804)
v • d • e


Text

Retrieved from "https://kanterella.com/w/index.php?title=ML080720639&oldid=5333955"